By Ross Malme
President and CEO
And by Pete Scarpelli
Vice President, Strategy & Business Development
October 24, 2001 — A DOE white paper submitted to the agency’s National Transmission Grid Study 2001 explores the benefits of load response programs to manage transmission congestion. The white paper follows.
Changes in the US electricity industry have resulted in generation and transmission issues that threaten the reliability and economics of effective energy delivery.
Immediate and Cost-Effective Solution:
While long-term planning initiatives for generation and transmission are both needed and underway, an effective and affordable solution is close at hand: Price Responsive Load Programs.
Load response is the critical third element in the overall electric system, and repeated studies and ongoing programs have demonstrated that effectively managing demand can have a dramatic impact on mitigating transmission congestion.
RETX firmly believes that the industry and the nation must invest in transmission and generation assets. These assets provide critical infrastructure that consumers demand and should receive. Our comments are intended to illustrate that load response solutions can be designed and implemented quickly.
Furthermore, they are cost effective solutions that should be considered as part of an overall congestion management strategy that also includes transmission and generation assets. This paper will focus on the benefits of load response solutions and why these solutions are an essential leg of the “three leg stool”.
The energy industry is rapidly evolving. FERC order 888 deregulated the wholesale electric market only a decade ago. Over the last five years several states have begun deregulating their retail electric markets and FERC has recently requested the formation of four super-regional RTOs. Unfortunately, this process has caused the industry to delay infrastructure investments in new generation and transmission because of cost recovery and regulatory concerns. Fortunately, new generation and/or transmission are not the only way to manage the current transmission congestion issues – price responsive load programs are relatively inexpensive and simple to implement. More importantly, price responsive load programs can reduce transmission congestion expenditures.
Over the last couple of years, load response programs have gained significant interest throughout the industry. California instituted programs to help avoid rolling blackouts. Utilities in the Northwest developed load response programs in order to sell power into neighboring markets where prices were higher.
Many retail energy service providers have developed programs as marketing and competitive differentiation tools. Independent System Operators (ISO) in New England, New York and PJM developed programs to assist with grid management and reliability. All of these programs successfully achieved their various missions. In fact, many California officials proudly claim that Californians reduced their overall demand by more than 10% over last year.
RETX offers an Internet-based load response system called Load Management Dispatcher (LMDTM). Several energy marketers and utilities use LMDTM in various regions of the country and RETX provides the system infrastructure for ISO NE’s Load Response Program. This summer, ISO NE proved that loads respond to price signals if they are given the right tools and the right signals.
Case Study: ISO New England Load Response Program
This year, ISO NE offered one of the most innovative Load Response Programs (LRP) in the country. The program showed that not only will loads respond to price signals, but also with the right technology ISO NE can visually see loads respond. In the future, this infrastructure will allow ISO NE to use these assets along with generating resources for transmission congestion relief by distributing appropriate price signals for localized load response events.
ISO NE offered two “flavors” of LRP this summer: Class 1 and Class 2:
The Class 1, Emergency Response Program is essentially a call option. ISO NE has the ability to call on specific end users who are willing and able to reduce their demand when the ISO NE deems it necessary to do so.
In return for this call right, the ISO NE compensates the parties by paying them the hourly Thirty Minute Non-Spin Reserve (TMNSR) clearing price for being available and the actual energy-clearing price when called to act. This equates to the Emergency Load Response programs offered in other regions.
The Class 2, Economic Response Program is voluntary. This program was designed to effectuate price responsive loads. When the forecasted market price for energy exceeds $100 per MWH, the ISO NE notifies participants that they can reduce load and sell that reduction back to the grid. Participants are not paid any reserve payments; therefore the ISO NE does not retain a call right. This is similar to the Economic Load Response Programs offered in other regions.
The primary objective of the LRP was to improve grid reliability and reduce certain pool-wide operating expenses. ISO NE estimated that approximately 500 MW of Class 1 load response would allow savings of up to $30 million by reducing the amount of additional generation necessary to replace operating reserves that would be called upon in the event of a loss of a large generating resource. Fortunately, ISO NE has not had to commit additional generating resources on a regular basis because of their efficient reserve markets.
Therefore, loads only respond to top tier system emergencies or economic opportunities by design. This solution provides a symbiotic relationship between LRP and the reserve markets as well as forming an effective asset management strategy for managing grid wide reserves.
However, the primary project goals did not take into account the benefits that the system could receive for localized load response. According to ISO NE’s 2001 Regional Transmission Expansion Plan (RTEP01), New England incurred over $80 million in added expenses over a one-week period because of the Maine / New Hampshire interface constraint.1
Over time, the RTEP01 estimates that congestion problems could cost the region an additional $125-600 million per year.2 By developing robust price responsive demand programs that target congested areas via appropriate price signals, LRP assets could effectuate reductions in these anticipated expenses.
The city of Boston is one of the major congestion zones in New England. The 2001 LRP program provided more than 500 MWH in that zone during congested periods this summer even though they were not specifically used for congestion management. Since loads have shown the ability to respond as desired, they should be considered as real assets to address congestion management problems and be compensated for the value they bring towards addressing the problem.
Load response increases as prices increase. This fact coupled with the congestion problems that New England incurred, has caused ISO NE to begin evaluating ways to better utilize its LRP to address congestion issues. In fact, the ISO NE is preparing to implement a Congestion Management System (CMS) that will provide zonal price signals to market participants. These price signals can also be used to attract end users to the LRP and trigger congestion management events.
Load Response Costs Relative to Other Options
The Edison Electric Institute (EEI), an association of investor-owned electric companies, estimates that the industry needs to invest about $56 billion over the next decade in order to maintain transmission adequacy. They also estimate that this is about half of the investment that is needed for new generation.1 This means that in order to keep up with anticipated demand levels, energy requirements, and system maintenance, the industry will need to invest approximately $180 billion in the next 10 years. While this number is staggering, it is not impossible to understand in light of rolling blackouts in California and wild price swings in Texas and the Northeast.
There are three ways to alleviate a congestion problem: 1) build new generation in the region; 2) build new transmission to the region; and/or 3) initiate LRP in the region to reduce demand when congestion occurs. A combination of all three solutions is required to cost effectively and efficiently manage transmission congestion problems.
EEI calculated that a 5% demand reduction reduces market prices by 50%.2 This statistic alone should cause a national focus on load response programs. But when the statistic is combined with the relative cost comparisons and ease of implementation that LRP can provide, the market should consider significant investments in LRP as a way to reduce the overall required investment of $180 billion. Based on our experiences, we estimate that the cost to initiate an LRP is approximately $10-15 per KW. This includes system infrastructure, near real-time metering, marketing and sales.
While on the surface LRP looks more expensive than new transmission, it must be recognized that 1 MW worth of transmission is not installed. In fact, EEI estimates that it costs $1 million per GW-Mile to install a new 345kv transmission line.5 Assuming the average new transmission line is approximately 50 miles, then the average investment is about $50 million per line. This does not include the logistical and legal issues and time required for new right-of-way abilities. Whereas given the right price signals and market rules, an LRP can be put together in a few months at considerably less total expense.
As a bonus benefit, LRP can provide significant environmental benefits as well. ISO NE estimated that at a scale of 500 MW their LRP would reduce region-wide emissions of CO2 by 2,000 tons, SO2 by 200 tons and NOX by 280 tons per year.
Industry Changes that Make Load Response Easier
The industry is migrating away from vertically integrated utilities towards market-based solutions. It is not entirely clear who is responsible for making this investment and what business model will support it. Therefore, utilities have deferred some of their investments and a new breed of independent power producers (IPP) has emerged. While it is impossible to transform a $350 billion energy industry overnight, some encouraging signs have emerged.
PJM, widely regarded as the most successful ISO, operates markets based on Locational Marginal Pricing (LMP). The intent was to let the market decide, with a little regulatory guidance, where the best place to invest new transmission or generation is in light of system demand and congestion problems. These same price signals make it easier to determine where the best load response locations are by making MW in one region more valuable than MW in another.
FERC has implied that it believes the PJM model is a good one to follow and other regions are starting to hear the message. For example, ISO NE’s new Congestion Management System will provide regionalize price signals to assist with congestion problems. The Southeast RTO has stated that LMP is the best way to manage congestion and that load curtailment programs should be included as one of the available resources.6
FERC Order 2000 and a few subsequent related orders have requested the formation of four super regional RTOs. This will make it easier to move power throughout a region and it should make the interconnected grid more reliable and economically efficient. This order also makes it easier for federal policy to proliferate LRPs throughout the country.
As stated above, the Southeast RTO has begun to look at LRPs as a way to manage congestion problems. In a similar vein the Northeast RTO (the proposed combination of PJM, ISO NE and NY ISO) are evaluating many LRPs for congestion management and regular market participation at a detailed level.7 This group is in a very good position to take leadership on these issues because their respective 2001 LRP took into account many market-based issues during their drafting, implementation, and operation.
Internet communications are making Load Response Programs easier to implement and operate. At ISO NE, RETX provides an Internet-based notification and monitoring system. ISO NE has the ability to notify specific zones of end users and monitor their load response performance. Unlike old style interruptible contracts, the Internet based communication system allows for much faster and more efficient communication of load response events as well as near-real time performance visibility.
With these features, New England LRP participants are able to provide congestion management, capacity requirements, and needed energy based on appropriate price signals. While this is still an emerging industry and there are several firms that provide this sort of service, ISO NE has made the best use of the technology thus far by giving the control room operators the ability to economically dispatch LRP assets as needed and where they are needed.
The Congressional Budget Office (CBO) has also recognized the benefits of price responsive loads. In their report to Congress on California restructuring and pricing problems titled “Causes and Lessons of the California Electricity Crisis”, the CBO stated that; “Even a small drop in electricity use – like the decline that occurred in San Diego when the price freeze there was temporarily lifted – would have been enough to let the state avoid some of the disruptions it has faced.”8
The report went on to say:
Price signals should encourage consumers not only to buy more or less power now but also to invest in the ability to adjust their future power use. Some of the same demand responsiveness that results from having consumers pay market prices may also be achieved if utilities either compensate customers for reducing their use or allow customers to resell power to others (in which case, a third party is paying them to reduce their use).9
Our point is that the market is transforming itself from a vertically integrated utility model towards a more open market-based economic model. Each incremental change makes it easier for end user loads to respond to market price signals. Right now in markets like New England, consumers and LSEs are investing in demand responsive technologies and distributed generation assets.
They are ready, willing and able to respond to market price signals. If these consumers are allowed to participate in the markets and the right infrastructure is put in place, they can have a dramatic impact on the investment required to deal with transmission congestion problems.
1. Develop policies that make it easier for load to directly participate in markets; let load respond to prices
2. Support FERC Order 2000 request for Super-Regional RTOs
3. Insist that all RTOs implement load response programs with a goal of at least 5% reduction in maximum demand
4. Insist on immediate implementation of LRP at the RTOs/ISOs
5. Implement Internet LRP communication systems
6. Invest in load response solutions
If market rules are modified to make it easier for loads to respond to prices, LRP can prove to be a valuable asset for congestion management and available capacity. The Department of Energy, in coordination with FERC, can have a dramatic impact on load response availability. Throughout the majority of the country most end users still do not have the ability to respond to prices. Your actions can change this by asking the various RTOs to institute LMP (or its equivalent) and by developing market-based load response programs. Such actions could save the nation billions in investment dollars by utilizing assets that already exist.
1. ISO New England, 2001 Regional Transmission Expansion Plan, August 21, 2001, page 9
2. ISO New England, 2001 Regional Transmission Expansion Plan, August 21, 2001, page 10
3. Edison Electric Institute, Transmission Planning for a Restructuring U.S. Electricity Industry, June 2001, page v & 9, www.ehirst.com/publications.html
4. Edison Electric Institute, Retail-Load Participation in Competitive Wholesale Electricity Markets, January 2001, page 5, www.ehirst.com/publications.html
5. Edison Electric Institute, Transmission Planning for a Restructuring U.S. Electricity Industry, June 2001, page 9, www.ehirst.com/publications.html
6. Federal Energy Regulatory Commission, Mediation Report for the Southeast RTO, September 10, 2001, page 66, Docket RTO1-100-000
7. Federal Energy Regulatory Commission, Administrative Law Judge Mediator’s Report to the Commission, September 17, 2001, Docket RTO1-99-000
8. Congressional Budget Office, Causes and Lessons Learned from the California Electricity Crisis, September 2000, page 11.
9. Congressional Budget Office, Causes and Lessons Learned from the California Electricity Crisis, September 2000, page 45.
10. Energy Information Administration, Assumptions to the Annual Energy Outlook 2001, December 2000. Table 43. http://www.eia.doe.gov/oiaf/aeo/index.html