|
|
|
|
Peak Load Management Alliance |
Volume 6 |
|
Table-of-Contents |
|
|
Notes from the Editor If you attended the recent Peak Load Management Alliance meeting in Washington, D.C., you no doubt were dazzled by the array of provocative presentations. Whether it was peeking into the mind of a market monitor or hearing a Nobel Laureate speak from the heart about his educational challenge communicating load management for over a decade, there was something for anyone interested in energy markets. As usual, I have tried to capture those presentations in this quarterly newsletter. In this meeting, you will note a shift away from ISO program structures to frank insights about implementing these programs in today's evolving regulatory and struggling competitive markets. The good news is that the diversity of ideas and opinions was expressed with an eye towards sharing insights and improving the ongoing business models. The bad news is that the soft forward markets and the meltdown in counterparty creditworthiness are challenging everyone in the market. For those of you who joined us, here is another set of CliffsNotesTM you may wish to distribute to colleagues who could not attend. For those who couldn't be there, I hope you find these highlights helpful and certainly hope you will grace us all with your presence at the next meeting scheduled for October 20th - 21st in Chicago, Illinois later this year. Finally, pay special note to the next section as Ross outlines a landmark project opportunity for PLMA members to participate in an international effort to stabilize demand response resources. |
|
Chairman's Corner Ross opened the meeting with some highlights of his recent presentation for the International Energy Agency in Paris, France. Ross attended these meetings on behalf of the PLMA. Other PLMA Board members also in attendance were Dan Violette and Bernie Neenan. As a result of these presentations, IEA sent Mr. Michael Jones as its representative to this PLMA meeting, and he presented an overview of IEA activities at lunch on the second day of the meeting. Ross's comments on the IEA meetings indicated that approximately 70 people from around the world attended including Dan Delury, Executive Director of the Demand Response and Advanced Metering (DRAM) Coalition and Alison Silverstein of FERC. The IEA convened the workshop due to a growing need for the implementation of demand response by member countries on a global basis. Many people within the agency now believe that we must view demand response in competitive electricity markets similar to the way we view the value of the Strategic Petroleum Reserve to the oil industry. One cannot rely exclusively on market forces alone to invest in the necessary infrastructure and capacity from demand response and that it must be driven from an overall policy perspective to assure its availability when needed to mitigate price volatility and reliability risks. Based in Paris, the International Energy Agency (IEA) is responsible for addressing international energy policy issues. One of IEA's key mandates is enabling competitive markets for electricity on a global basis. On April 8th and 9th the PLMA presented a project concept to the IEA Demand Side Management (DSM) Executive Committee in Canberra, Australia. The project concept was to establish demand response as an integral part of competitive electricity markets and to develop the necessary business models and technology infrastructure to assure its implementation. The project concept was enthusiastically received and approved by the DSM Executive Committee. Over the next several months PLMA will be working with the US Department of Energy (DOE), which is the US representative to the DSM Executive Committee and with the participating countries to establish the project scope, deliverables, work plan and necessary resources to complete the project. It is anticipated that the PLMA will host a multinational workshop on the project in September of this year to reach agreement upon the key elements of the project with the participating countries. PLMA then plans to present the project to the DSM Executive Committee for formal approval at its next meeting in October of this year. Commitment to this project by the IEA is a major milestone for the PLMA in establishing the organization as a worldwide leader in all aspects of demand response. The PLMA is very pleased to be working with the IEA and looks forward to partnering with its member counties to deliver the intrinsic value of demand response to global competitive electricity markets. |
|
Dr. Smith offered some of the most memorable quotes for the meeting, in one instance pointing to the fact that Jesus was born in a manger because they didn't build enough hotel rooms to meet peak demand. I guess his point was that demand response was working even back then. Perhaps his funniest moment was when he grabbed a ten-year old viewgraph about price spikes saying, "Look, you don't need new visuals to prove demand response is valuable. Here is an old one. It is still as good today as it was then." Dr. Smith has been working on alternatives to rate of return regulation since 1984. The options he has considered included the concept of demand side bidding into the market so that there would be a two-sided auction. The idea was rejected back then, but was picked up in 1991 in New Zealand and in 1993-1995 in Australia. He now works on smart computer system market simulations where optimization models can combine the best attributes of decentralization and coordination. He is a believer in markets: "Give market participants the minimum amount of information just to let them play in the market." He believes the central problem has to do with what goes on between the substation and the customer to balance supply and demand. Furthermore, Dr. Smith believes there is an optimal scarcity level and price is used to ration. That's when you get your best solutions. When customers fail to see market prices, it is typical for subsidies and taxes to occur through the political infrastructure. He believes this is illogical and intrinsically unfair. In his research, he decided to see whether and how a portion of the load in DR could influence price spikes. He compared human buyers and robot buyers along with the differences between strategic bidding vs. passive bidding. He also looked at a distribution of owners of generation (companies owning a fleet). He also rigged market power and non-market power situations and staged the ownership of the generation so that the peakers would compete with the load followers. The sellers bid in four blocks each day and that intersects the robot demand curve. The really interesting thing is when the demand side enters the market, the equilibrium is lower and price volatility is reduced. The Progress and Freedom Foundation brought in utility executives in 1995 and they concluded, as a result of this research and experiment, it was the best for markets if customer demand flexibility could be developed. But, alas, the executives were more interested in the stranded cost recovery at that point in time. As Vernon said, "There are people who do not know what is actually in their best interest." He also pointed out that as soon as you go over to an "as bid" vs. Dutch auction it results in higher prices and he offered another gem of wisdom: "If it's not raining, you don't have to fix the roof. Then, when it is raining, you just can't get up there!" Other insightful comments for today's markets are that you have to fit what the consumer wants within a survivable business proposition. You have to think differently by making money on making less power. You have to get the incentives right. You can insure against price risk but that may not assure outage risk. Derivatives should come in only after the physical hedges. You have to worry about transaction costs. And, finally, the process of innovation should reward search. Finally, Vernon offered some contrasts and thoughts about how the airlines industry deregulated the routes, but not the airports. Some of these ideas would take pages to consider, but here they are as a series of one-liners: Suppose you ran an auction for takeoffs and landings? Design a market to bid for the service package you want. At the time of airline deregulation, no industry expert forecasted the hub and spoke system that emerged to maximize total throughput. Direct service between secondary cities didn't happen. No one could make money doing it. People tried and went bankrupt. People want frequency of service not just convenient point to point. The market found that by trial and error. Southwest is now exploiting this strategy. You couldn't have surveyed customers at the time the markets emerged … they wouldn't know what they wanted until they experienced it. The innovation process has to be allowed to search for value. Therefore, people willing to be interrupted should be exempted from the costs of providing those reserves to others. The markets have to be designed to make choices and run risks. Dr. Smith's plain speaking style and homespun humor may seem trivial to other economists, but was a delight to those seeking to innovate in today's perplexing impasse between political will and sound economic market design. |
|
His view was obviously much broader than demand response alone. He expressed his advocacy of competitive markets because they allocate resources and organize relatively complex processes most efficiently. Prices should be just and reasonable, and deregulation requires competition to enable these same objectives. Market monitoring and mitigation is supposed to spot flaws in the market rules and to detect and propose remedies. The three roles are real time screening (bids, dispatches, line flows), investigations of specific issues/situations, and periodic analysis and reports (especially annual) to show how the markets are performing. It is in those reports that specific recommendations are usually made about demand response. His organization focuses on the conduct of the participants rather than the prices themselves. Therefore, he watches activities such as physical withholding or taking other actions that restrict the supply/demand process. He also watches for economic withholding (raising a generator bid so as not to run or raise the clearing prices). He believes the answers to mitigating market power are to promote transmission investments to reduce congestion and associated locational market power, remove barriers to investment in new generation, facilitate demand-side participation in the market, and divestiture (reducing concentration of supply ownership). Interestingly, he believes bids can and should include foregone profits from future sales. His findings determined that the Northeast markets are very competitive, outside of locational market power where "pivotal" suppliers have a natural edge. He also indicated that the SMD markets are not designed to reliably reveal the true value of energy during supply shortages ("scarcity pricing"). This problem relates to how the markets set prices when in a shortage. He expressed concern about the occasional "out of merit order" results that sets an incorrectly low market clearing price. He shared thoughts like the following: If the marginal source of power is coming from reserves, and if that is the last dispatched unit, what is that worth? Should that be at the bid cap? His thought was that prices should be set at the bid cap whenever you are deficient of reserves, in part, because these price signals are key to the peaking capacity capital decisions. The size of bid blocks and the bid lead times interact with these effects. He also indicated that one key is that the demand response should set the prices when constraints occur. |
|
New Zealand is one of the most deregulated markets in the world (right behind Singapore). It consists of a 244 LMP node, voluntary, ex post wholesale market with heavy reliance on spot markets in price setting. Sustainability is at the core of the energy policy in NZ. Up to 20% of the load was set up historically using ripple control back when it was all bundled under the regulated utility ECNZ before the market was liberalized. The lines (we call them wires in the US) companies have since lost the relationship to the customer, so retailers are now the conduit through which customers are influenced. The generators are also generally paired to most of the retailers so there is a split incentive situation (one might say that they can become "conflicted" in their views about demand response). . . One of the most progressive retailers, Meridian Energy, with a great deal of hydro exposure, broke away from the ambivalent pack about a year ago and got 70 MW of demand response using Apogee Interactive, Inc.'s Demand Exchange® Trading Platform. EECA documented their experiences along with a market research effort to identify the full extent of the demand response resource available nationwide. This was recently published in a report that is publicly available at http://www.govt.nz/default2.asp . That report identified between 250 and 900 MW of demand response (depending upon the time and frequency of availability desired). Ewan noted that customers desperately wanted a day-ahead market. He also felt that the demand-side needs to aggregate itself together and speak with a larger voice. Most retailers are currently offering fixed price, variable volume, fixed price fixed volume, and partial spot market exposure. Customers are becoming uneasy about the increasingly volatile and high priced spot exposure. However, commercial and smaller end users are still not paying much attention to these increasing risks. Other work underway is a move to real time pricing manifesting itself as 5 minute indicative pricing, which has been deemed very successful. Forecasts of prices have proven to be quite unreliable in some nodal areas while OK at others. Educating end users to understand the value of and request demand response programs from retailers has been identified as a key priority. He indicated that the Meridian customers liked the quantifiable benefit from the operation of the Trading Platform in contrast to RTP where the value of responding would not have been "recognized and captured." |
|
Long-Term Resource
Adequacy Derek
Bandera, FERC Eric
Hirst, Eric Hirst Consulting Joel
Gilbert, Apogee Interactive, Inc. Dan Violette of Summit Blue Consulting and Greg Bullington from Kansas City Power and Light presented an overview of what PLMA is doing besides running conferences. Two white papers were published and are considering a new activity - a bi-monthly communiqué for regulatory and policy making organizations. These are available at http://www.peaklma.com. They also thought that the soft market has created headroom for retailers to enter the markets, and that should lead to retailers becoming interested in DR as that headroom diminishes. Dan believed a retailer could then lead with comfort and introduce demand response. Flat pricing defeats the business case for DR and disables the vendors. He believes we need to price what's scarce. The third white paper is to consolidate frequently asked questions from a program planning, design and operational effectiveness. Pivot points are the FERC, PUCs and the ISOs so these players need to be kept informed. At this point it is being referred to as a communiqué. |
|
Chris Siebens, Manager of Demand Response Programs, First Energy Three states, three contexts, and three business cases have to be created. As Chris chided: "Redefined utility roles easily leads to program discontinuities." Penalties for non-response were very discouraging to customers. And, getting the details right makes all the difference: Payments to customers, people to put the programs on the street, and infrastructure to deliver the programs and results. The "hard number" benefits are economic energy, capacity, capacity cost savings, and revenues for services. The soft number benefits are T&D benefits, goodwill, and market effects. Believers accept the soft numbers and disbelievers discount them heavily. Chris noted that there is regulatory good will and customer good will. In NJ there recently was a BGS auction (which is part of a plan to have larger customers face an hourly energy price). Are there direct and economic benefits, Chris asked? Sure, but it depends. It is very hard to put the value stream back together once they are broken through restructuring. Chris questions whether a regulated wires company can properly recognize the value of congestion. They haven't been able to come up with the forward curve for them. They may have to auction off their DLCs to get a handle on that, but, at today's prices, it may not be worth what it costs. William McNeil, Director of Energy Acquisition, Exelon Bill pointed to some interesting questions when you look at this issue from a default provider's perspective. They have 20,000 non-residential shopping load (2,600 MW), 9 certified alternative suppliers (Retail Electric Suppliers), and 12,000 MW of IPPs built between 1999 and 2003. ComEd successfully petitioned to have electric service declared competitive for customers >3 MW. Therefore, there is a three-year phase-out of their obligation to provide a default tariff. The shopping dropped from about 45% of the load in early 2000 to about 9% now. Bill believes a key point is price transparency. This is all about the risk recognition and getting customers to face prices. This is all about volume and price risks and offsetting capacity and operational cost risks. If everything is a straight pass-through, the default provider will not care. But, if there is hindsight prudence review, managing this matters. Bill believes some form of performance-based ratemaking or alternative regulation would provide performance incentive for the default provider to consider demand response in the overall portfolio management. More wholesale price transparency and linkages to retail prices are essential for larger customers as an underpinning to working markets. Ken Malloy, CEO, Center for the Advancement of Energy Markets (CAEM) Ken livened up the afternoon with a non-stop performance somewhat akin to a Saturday Night Live rendition about energy policy and the energy industry at this time. His theme was a bridge over troubled waters that posed four key points: 1. We are in a war over an
idea: open markets for energy 2. We are losing the war 3. How will we know
success when we see it? 4. DR is merely one more
battleground. The Center is a four-year old think tank on energy restructuring. They are an independent, non-profit change agency. They are not a lobbying group or an association, and are very complementary to PLMA. We need to rethink how we manage competitive network policies. The issue is not whether we will get there, but how long is it going to take and at what cost. Ken believes it takes a crisis to get movement. He is the publisher of the RED index. He believes the Georgia natural gas market is a real market. DR is a good idea, but it is in a sea of good ideas. He believes we are spending too much time on policy, and not enough on a plan or an organized strategy along with funding (perhaps using sympathetic foundations). Jim Eber, ComEd (Exelon Energy Delivery) In 1998, the high profile reliability issues in Chicago forced change. ComEd was no longer going to ask customers to help without paying them. They rolled out a whole demand response program portfolio. They built-out and now manage the PLM portfolio of about 1400 MW. The VLR program has both a wires and an energy element, so if the customer shops, others take that element. They have been able to delay a transformer installation for a year. ComEd limits minimum participation to 5% of the peak demand or 10 kW. Jim feels there needs to be an "entry level" program for customers, and then grow their participation. They have sent engineers into customer facilities to create custom demand response plans, and now have 30,000 participants out of the potential 55,000 IDRs. Ronnie Chahal, Director of Portfolio Management and Structure at Energy America They serve load for everything south of Corpus Christi, Texas. This includes 850,000 price-to-beat customers and 2,200 MW of load, about 4,000 MW at peak. The load is extremely weather sensitive. ERCOT does not have an ICAP market. The average balancing market recently hit $200 and $480 per MWh in a sea of much lower but still high values. He feels there is some expectation of the demand response in the implied heat rates. They have done deals for demand response and consider it an element in future customer price offers. Current retail offerings include the price-to-beat (less than 1 MW) based upon the 12-month average of the NYMEX gas strip. That PTB can change twice a year. Fixed-price/fixed-term with 3-year price certainty are also offered. The incumbents do not offer these assurances. He felt that the size of the customers in demand response programs would be limited by the costs of settlements and other back office costs. Mary Elizabeth Tighe, Energy Results Mary Elizabeth stepped up to round out the last session of the day. She manages a demand response program for a competitive supplier. In order to close deals, she has to answer three key questions from the customer: 1. Why should I be
interested (the market price signals)? 2. What do I have to do? 3. What am I going to get
in return? Getting market price signals: most customers
are taking bundled retail service under a fixed rate. Her questions include: The infrastructure investment question is a deal killer. Customers simply will not invest in the required infrastructure. There is perception that there is a greater risk to reduce than to continue consumption. The risks of participation in a program where there are penalties hanging over their head. So, they have no deal. What they can hope to change is that policies facilitate demand response. Michele Brown, Allied Utility Network Michele described how AUN went into the ISO NE market with no relationship to the customer, and tried to recruit customers who were unfamiliarity with the regional program. As she said, she encountered a recurring customer concern: Whose problem is this? (That is, the customers had expected the energy companies to solve the problem.) She found it took 4-6 months to recruit customers. She also pointed to a lack of consistent vision across the silos of DEP and PUC, and ISO in the region. |
|
New Research in Demand
Response Professor Dick Schuler, Cornell University Why laboratory experiments, you may ask? Well, to avoid the social cost of experiments of the whole (e.g., California), the fact that it is a lower cost alternative, and to test out pilot or experimental strategies. But, how do you represent the demand side? You have to have some kind of control. You have to create an induced valuation. You have to pay people real money to get them to behave. Dr. Schuler's experiments included Baseline, Emergency Demand Response Program, and RTP. Their students are going through 12 days of experimental design. They will also introduce a survey in between the experiments to see the attitudinal shifts (changes of opinion after they get experience with these). Then, they are going to two-sided experiments this coming summer. Kathryn Tholin, General Manager, Community Energy Cooperative (CEC) This organization is focused on how to build affordable, sustainable, environmentally friendly communities where small customers are not left behind. The Energy-Smart Pricing Plan has two key partners: CEC and ComEd. The CEC was formed in 2000. The third partner is the State of Illinois. The goals include improving neighborhood electrical reliability, reducing energy costs, permitting community participation in the new markets, development of community energy efficiency, load management and generation strategies, linking existing organizations, and aggregating community purchasing power. The ESPP is a residential market-based pricing plan, with tools and information for participants to manage their energy use, and is an experiment to determine the costs and benefits. ComEd provides the rate and the metering/billing system. CEC does the notification, education, and program execution. The question they are wrestling with is "will customers participate?" and "what will they actually do?" Customers get day-ahead prices and are notified if the day ahead prices are above $0.10 per kWh using email, telephone, and their website. Chuck Goldman, Lawrence Berkeley National Laboratory. Chuck reviewed an evaluation of NYISO demand response programs. The report is available on the NYISO web site. The study tried to understand the "why" questions about customer attitudes to the ISONY program: the key drivers and barriers to participation. They wanted to understand specifically why there were only 25 customers and only about 14 MW in the DADRP. They wanted to understand the value created by an in-person price-responsive-load-audit compared to a telephone survey. Customers have to bid 1 MW by 5 a.m., and are paid the higher of their bid or the cleared price (Dutch auction) and had penalties for failure to perform. The barriers were that there were low awareness levels, informational and knowledge barriers, and little recognition of ancillary benefits. They were surprised that there was awareness among customers who were participating in other programs (the emergency program). This may indicate a communication bias. Inadequate compensation or the benefits-risks were also a problem. They also determined that a day-ahead program is not for everybody. They determined that customers preferred knowing the price rather than submitting bids. There is a significant need for education and training about how markets work so they can understand how to bid. Energy information tools were voted as most desirable. The recommendations included that NYSERDA should develop a broad set of customer education and training programs, integrate DR with EE program strategies, and link system reliability benefits with customer participation in economic programs. They also identified a key role for load aggregators, but one question that remains is will customers migrate from emergency to economic programs? There seems to be a limited incentive to migrate. They determined that customer acquisition costs are critical given the soft energy markets. Customer capacity payments are critical to retaining customer participation. |
|
Technology for Successful
Demand Response Adriene Wright, Director of Development, Electricity Innovation Institute, EPRI The Consortium for Electric Infrastructure for a Digital Society (CEIDS) has a focus on the longer-range strategic R&D issues and acts as a catalyst in a public/private partnership. The ubiquitous use of microprocessors is increasingly exposing the analog-designed electric system to its inadequacy. Power outages and disturbances are at least $100 billion a year in economic impacts. The initiative looks holistically at everything from the bus-bar to the ride-through and power quality insulation methodologies. They envision a self-healing grid and a dynamic information system linking customers to markets and market counterparties. Owen Howlett, Lighting Research Center There are 52 million fluorescent ballasts installed each year and about 30% of that can be shed. The amount of money saved by a customer is about $3 per ballast per year (ranges significantly). Since 85% of the ballasts are the cheapest end of the market, the LRC set out to target that opportunity. Their other goal was that the whole initiative has to be "invisible" to a contractor. They are envisioning a power line carrier with bi-level dimming (100% and 70%). The whole extra cost is envisioned to be in the $2-$3 level per ballast. They have a proof-of-concept demonstration unit under the sponsorship of CL&P (NU). When people were informed about the societal benefits of load shedding, they became much more accepting of the light dimming process. Field trials are planned. They are going to investigate out what overriding consumers may do. The override has to be local and accessible. Doug Backer, Cannon Technology Doug spoke on mass-market pay-for-performance demand response. Doug has published some of his recent thought provoking concepts in recent issues of the PLMA newsletter. He indicated that two utilities are testing this concept in a limited sense. Doug sees the need for a low cost, price responsive demand management program that is targeted at mass-market customers where individual meter reconciliation is potentially not cost effective at this time. Doug also sees a new model for customer demand response participation along a continuum … Unrestricted comfort vs. savings as a continuum. Everyone lives somewhere along the continuum. His concept is to use the Dutch auction. Customers set an event value threshold, depth of control (setback, duration, cycle percentage) with day of the week adjustment. The event payments are accumulated in an energy savings account. Program partners could match the benefits with a "coupon value" for parallel goods and services. His idea is that the query could evaluate the bid stack in this resource (an elasticity estimator). Measurement and verification could be done by sample statistics. He believes there could be an inspection award partnership to police free riders and non-performance. Doug also thought the CSP could retain the arbitrage between the markets and the customer's bid stack. Keep the ideas flowing Doug, we need all of them to develop a vibrant free market! Bernie Neenan, Neenan and Associates and Chuck Goldman, Charles Goldman, Lawrence Berkeley National Laboratory (LBNL) led a Pre-Conference Workshop on the Methods and Practices for Evaluating the Performance of Demand Response Programs. Bernie Neenan and Chuck Goldman presented a conceptual foundation for establishing the value of demand response in a competitive market environment developed in conjunction with the Center for Electricity Reliability and Technology Solutions (CERTS) to evaluate demand response (DR) programs implemented by the NYISO. The valuation methodology emphasizes the distinction between DR programs that provide the system operator or ISO with capacity resources and programs that allow DR resources to compete against generation for the provision of energy in day-ahead (or real-time) markets. He demonstrated that reserve programs mitigate the consequences of forced outages, and consequently their value to the system (and society) is associated with the value of lost load (VOLL), and not prevailing market prices. Furthermore, he showed that reliability is a public good, the provision of which if solely provided according to individual private values of end users will fall short of the socially optimum amount. Consequently, DR resources have the greatest value when placed under the operation of the system operator and valued according to the outages they prevent. Bernie then presented the results of the application of this valuation methodology to the DR programs implemented by the NYISO. The emergency program produced benefits to stakeholder that were 6-15 times the amount paid to participants in 2001 and 1 to 5 times in 2002. The lower performance in 2002 is attributable primarily to the program's success at attracting participation; the DR resources available exceeded the system reserves needed. As a result, the NYISO has implemented a provision whereby some DR resources will submit a curtailment bid price that will be used to create a DR supply curve. System operators can dispatch what is needed, where it is needed. Moreover this dispatch method will establish the efficient price to pay those that curtail. The day-ahead market-bidding program (DADRP) produced strong benefit to cost ratios, over 3 to 1 in both years, where the benefits are transfers from producers to consumers. Additional benefits that inure to all stakeholders come from the reduction in deadweight losses, which are the consequence of retail prices that do not reflect the underlying cost of supply. |