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SMD is a major redesign of New England's wholesale electricity market that will result in a more efficient wholesale power market for the six-state region. SMD becomes operational on March 1, 2003.
SMD is based on a proven, fully operational system in place in the Pennsylvania -New Jersey-Maryland (PJM) market and is consistent with the Federal Energy Regulatory Commission's (FERC's) vision for standardized electricity markets in the United States.
The goal of SMD is to provide New England a market with fair and understandable rules that produce predictable results: greater economic efficiency and competition, enhanced power system reliability and reasonable wholesale electricity prices. SMD will:
SMD reflects the implementation of market improvements that were deemed necessary at the origin of wholesale free-market competition in New England.
ISO New England first launched a single energy clearing price wholesale market in 1999. At that time, free market competition was new to the electric power industry, so the early days of wholesale market operation in the U.S. were considered somewhat experimental. Each area of the country that developed wholesale markets created their own unique market design. This provided an opportunity to learn about wholesale market structures in New England and elsewhere.
ISO New England elected to implement SMD 1.0, a combination of salient portions of PJM Interconnection's market architecture and ISO New England's best practices, to enhance the wholesale electricity marketplace and to bring about significant benefits to the region.
SMD changes the way electricity is priced from a single price for the entire region to pricing electricity based on how much it actually costs to produce and transmit energy to specific locations. SMD also adds a financially binding, day-ahead market to the real-time market, allowing market participants to lock in day-ahead prices and reduce their vulnerability to price fluctuations that can occur in the real-time market. What's more, SMD provides expanded risk management opportunities to market participants.
The three most prominent features of ISO New England's SMD are the introduction of locational prices for energy, a multi-settlement system and expanded risk management opportunities.
SMD eliminates the absorption of congestion costs across the six-state region. Instead, locational marginal pricing (LMP) will set energy prices by location and will include the cost of congestion. LMP will reveal the true cost of serving demand at particular locations throughout the bulk power grid and indicate where investment in the system is needed.
SMD also introduces dual energy markets in New England: the day-ahead market and the realtime market. The first settlement relates to the day-ahead market's costs and payments while the second settles the difference between energy scheduled day-ahead and that which is actually delivered in real-time. The multi-settlement system provides mechanisms to hedge against the volatility of real-time prices and provides the correct price signals to influence economic and efficient real-time market behavior.
Finally, a new market tool called financial transmission rights, or FTRs, serves as a mechanism for market participants to offset higher wholesale prices caused by congestion costs. The revenues from the FTR auction, called auction revenue rights (ARRs), will be allocated back to wholesale market participants responsible for paying congestion costs associated with supplying electricity to serve demand.
ISO New England's SMD differs only slightly from the principles outlined in the FERC's Notice of Proposed Rulemaking (NOPR). Overall, ISO New England endorses FERC's efforts to develop efficient, robust and reliable electricity markets through the adoption of standardized market rules and procedures that will apply to all trading in regional markets throughout the country.
ISO New England finds that the standardization of the key features outlined in the FERC's NOPR, including multi-settlement, locational pricing and economic dispatch combined with financial hedging instruments, builds on the successful experience in existing markets. ISO New England's implementation of SMD highlights the symmetry of ISO New England's and the FERC's views on SMD. Therefore, ISO New England strongly supports the objectives outlined throughout the FERC's NOPR.
In some instances, ISO New England has provided comments to the FERC regarding areas where the Commission may want to consider alternative approaches, such as strengthening demand response and ancillary market design.
In the very near-term, the retail market will not be affected by the implementation of SMD. Every state, with the exception of Vermont, has "standard offer," or transitional pricing in place that dates back to the beginning of retail access. Under standard offer, consumers pay a set price regardless of the "true" cost of energy. This offers consumers insulation from near-term price increases.
In the longer-term, standard offer will expire in each state. The regulators and/or legislators within each of the states must then determine how retail pricing models will change. In the wholesale market, ISO New England expects to see wholesale prices decrease in most areas, but increase in areas that are afflicted with transmission congestion.
ISO New England completed a nine-month software-testing period, a series of market trials, a certified independent software audit and numerous training opportunities for market participants to prepare for the implementation of SMD.
ISO New England conducted a total of three external market trials. These trials established a simulated environment that allowed ISO New England and market participants to test the readiness of the SMD software, business processes and systems.
Additionally , PA Consulting Group, headquartered in London, England, conducted the independent software review of ISO New England's SMD systems and concluded that the SMD software is certified and ready for market start. The review and certification process focused on the written SMD documentation, including Market Rule 1 and the New England Power Pool (NEPOOL) Manuals and Operating Procedures, as well as a review of the SMD software components, including software for scheduling, pricing and dispatch. This review demonstrated that ISO New England's software is primed for the implementation of SMD and that the software operates in accordance with market rules.
Throughout the software testing process, ISO New England has worked closely with market participants to provide both training and resources to make certain all market participants are prepared for the launch of the new market. ISO New England has provided 50 training programs for all levels of users, beginning in September 2001. Total enrollment for training classes provided by ISO New England has exceeded 2,500.
Instead of providing one region-wide wholesale energy price, prices for energy under SMD will be calculated at 900-plus locations in New England. These locational marginal prices are determined by the cost of serving an increment of load at each location and will include the cost of congestion. When the system is unconstrained, the prices at each location will be equal. When the system is constrained, prices increase as more expensive generators are dispatched to relieve the congestion problem. In this instance, prices will vary by location.
Since each price reflects the cost of supplying one more increment of load at a given location, it provides a precise, market-based method for valuing energy that includes the cost of congestion.
Several categories of locations are defined in SMD: nodes, load zones and a hub. Nodes are points where power is injected or withdrawn from the system. Zones are aggregations of nodes. The hub is a special aggregation of fairly unconstrained nodes, designed to facilitate trading. Prices at the hub should not be affected significantly by congestion.
Generation will be priced nodally, while load (demand) will pay a uniform price for its zone. Load zones generally follow the political boundaries of the six New England states, except Massachusetts, which is sub-divided into three zones—Western/Central Massachusetts, Northeastern Massachusetts (which includes Boston) and Southeastern Massachusetts.
The price at each zone is the megawatt-weighted average of all nodal prices within the zone. Thus, relatively high locational prices at one node are averaged together with all other nodal prices within the zone to yield a single price for load.
LMP provides a more precise and efficient method for pricing energy in New England. In the original market, one energy clearing price—that is the economic price at which generators can be dispatched to meet demand—is set for all of New England. When transmission constraints block the most economic dispatch of the system, the entire New England region pays for the costs associated with relieving that congestion.
LMP prices energy by location. This price first takes into account the basic cost of energy. It then considers the additional costs associated with congestion. Should congestion occur within a specific location, the cost of that congestion will be contained to the area in which it occurs.
Transmission constraints increase the likelihood of higher prices within a congested area. On a constrained system, the least-cost generator cannot be dispatched, and a higher-cost generator within the constrained area must be paid their offer price to alleviate the congestion. That increase in cost is reflected in the nodal LMP. As the nodal LMP is aggregated for a zone, the average cost of energy within that constrained zone is also likely to increase.
At times, yes. In areas that lack sufficient transmission infrastructure to support requested imports or transfers or are lagging in generation, cost increases for energy are likely to occur.
In the short-term, LMP improves the efficiency of the wholesale electricity market by ensuring that the cost of congestion is reflected in electricity prices and ensures that the least-cost supply of electricity is delivered while respecting the physical limitation of the transmission network.
In the long-term, LMP helps relieve congestion by promoting efficient investment decisions. Because LMP creates price signals that reflect the locational value of electricity, participants can readily determine areas of congestion and will see the value of investing in generation, transmission and demand response programs.
The term multi-settlement describes the energy market under SMD. The energy market consists of day-ahead and real-time markets for electricity, each producing its own separate and unique financial settlement.
In a multi-settlement system, day-ahead offers from generators and bids from loads are used for determining and settling day-ahead energy quantities. Differences between energy scheduled day-ahead and that which is actually delivered in real-time are settled in the realtime market. In the day-ahead market, participants submit supply offers and demand bids for energy. In the real-time market, participants will, continuously throughout the day, be allowed to offer/request imports and exports of electricity with at least one hour's notice to the ISO.
The multi-settlement system allows market participants to secure day-ahead prices and reduce their vulnerability to price fluctuations that can occur in the real-time market. The day-ahead market is therefore a hedge against real-time price volatility. What's more, day-ahead price signals influence correct, economic real-time behavior—they produce greater certainty of generator performance and exert a powerful incentive for wholesale users to understand and manage their patterns of consumption.
Further, participants are provided with a broader range of options for participating in both the day-ahead and real-time markets. By expanding the horizon for energy transactions, the market becomes more liquid, more competitive, and more economically efficient. Opportunities and incentives for participants to manipulate the market are limited.
The original market is a single settlement market—there is only one offer period (real-time) and settlement period (after the fact) that exists. Unfortunately, this method of operation creates uncertainty and risk. The addition of the day-ahead market, in addition to a real-time market, mitigates this risk.
Also notable is the fact that wholesale demand will, for the first time, be a full and equal participant in the determination of the day-ahead wholesale clearing price and will continue to be able to influence real-time clearing prices.
When transmission congestion occurs on the bulk power grid, locational marginal prices (LMPs) will vary throughout the system. While these variations can provide incentive for efficient market operation, this volatility also creates uncertainty for market participants, especially for those responsible for serving demand in congested areas. To hedge, or protect, against the adverse impacts of having to pay higher LMPs caused by transmission congestion, market participants can bid for FTRs.
An FTR is a financial instrument that entitles the holder to receive a share of the excess payments collected for congestion costs that arise when the transmission grid is congested in the day-ahead market (FTRs are not offered in the real-time market). This dollar amount can be used to offset the costs of the congestion component that market participants have paid, or it can be an additional source of revenue for FTR market speculators.
Financial hedging instruments such as FTRs help market participants manage their congestion-related risks. FTRs provide certainty to market participants in the face of variations in day-ahead LMPs by helping them offset potentially higher costs caused by congestion.
FTRs can be acquired in three ways.
The revenues from the sale of FTRs will be distributed to auction revenue right (ARR) holders. ARR holders are either those paying congestion costs associated with supplying electricity to serve demand, or those paying for transmission upgrades that create new FTR capability. ARRs provide congestion-paying load serving entities a revenue stream that can be used to help insulate them against congestion costs or defray the costs incurred with acquiring FTRs at auction.
Under SMD, there are several ancillary services, including operating reserves, the regulation market and the installed capacity market.
The ISO compensates generators who provide operating reserves based on their submitted costs for providing energy, including start-up and no-load costs. This operating reserve compensation ensures that generators providing reserves are made whole of any expenses not recovered through the daily sum of energy payments. Special provisions provide lost opportunity compensation to generators whose output is constrained for the purposes of providing operating reserve.
Operating reserves charges in the day-ahead market are levied upon participants proportionate to their day-ahead market load obligations. In the real-time market, charges are levied upon participants whose real-time load deviates from the day-ahead schedule and/or whose generators deviate from day-ahead schedules and do not follow real-time dispatch instructions.
Market participants should take potential revenues and costs from operating reserve credits and charges into consideration when participating in both the day-ahead and real-time markets.
Under the original market in New England, automatic generation control (AGC) sets the proper flow and frequency across the region in order to provide moment-by-moment balancing of generation and demand on the system and maintain the 60 Hertz frequency. In cases of either inadequate or excess instantaneous supply, generators within a control area increase or decrease generation to restore the energy balance within the control area. Generators are provided financial incentive to ramp-up or back-down their generation in order to maintain this frequency.
With the implementation of SMD, this market becomes know as "regulation." ISO New England continuously monitors the system's balance. As this monitoring signals excess or under generation, generators are called upon and compensated for reestablishing frequency balance.
Under SMD, the original capacity market will be replaced by an installed capacity market (ICAP) that is based primarily upon the New York ISO rules and that reflects best practices from the three Northeastern ISOs. Under ICAP, generators receive compensation for units in New England. Load serving entities (LSEs), the participants that are responsible for serving demand, make this payment to generators across New England.
LSEs are told their estimated ICAP obligation at the beginning of each month and are responsible for procuring that ICAP requirement by month's end. A number of options exist for LSEs to secure ICAP early in the month, including bilateral contracts and a supply auction sponsored by the ISO that takes place mid-month.
Seams are barriers and inefficiencies that inhibit the economic transaction of capacity and energy between neighboring wholesale electricity markets, or control areas, as a result of differences in market rules and designs, operating and scheduling protocols and other control area practices.
Seams exist between control areas because wholesale electricity markets have evolved using different sets of rules and procedures. Such is the case among control areas in the northeastern United States and with their neighbors in eastern Canada.
ISO New England and its neighbors recognize the restraint that seams put on trading and have been working together over the past several years to lessen the differences that inhibit the free flow of energy between the regions.
The adoption of PJM market rules along with the installed capacity (ICAP) arrangements and a market mitigation plan substantially similar to those of the New York ISO, coupled with the application of consistent scheduling rules across all its external ties, will significantly reduce the differences among the markets of the Northeast.
By designing SMD in this way, seams issues will be reduced and market participants trading within the three control areas will find it easier to do business regionally.
ISO New England continues to make significant progress in reducing trading barriers to increase reliability and enhance competition. Future efforts, such as the ISO's ongoing work with the FERC, as well as upcoming plans to develop a coordinated system planning process with New York, ensure that New England and its neighbors will continue to derive benefits from the reduction of seams. ISO New England reports quarterly to the FERC on the progress of its seams resolution efforts.
Eliminating seams reduces trading barriers that exist between electricity markets in the Northeast and eastern Canada. For participants, the ease of conducting business across regions leads to a larger potential electricity market. This, in addition to more streamlined operations, enhances trading flexibility and choices offered to wholesale market participants, advances competition among wholesale market participants, and increases the reliability of the bulk power system.
ISO New England is responsible for monit oring the New England wholesale electricity market including both the overall market design and market participant behavior. Monitoring seeks to ensure that the markets are working fairly and efficiently and that market participants abide by the FERC-approved market rules and procedures established for New England.
Under SMD, monitoring will expand to include the day-ahead markets virtual bids and offers, financial transmission rights (FTRs), and the revamped installed capacity (ICAP) market. In addition, rules have been enhanced to more clearly specify the conditions under which sanctions may be imposed for physical withholding.
With the locational marginal pricing (LMP) feature of SMD, ISO New England's market monitor ing group can better address locational market power—market power that occurs in specific areas or locations—in New England. Locational market power stems from a supplier's ability to withhold resources and effectively raise prices within areas affected by transmission congestion.
The monitoring and mitigation structure under SMD reduces the likelihood of the exercise of locational market power by a particular supplier in congested areas while still allowing important local price signals. Specifically, ISO New England has the authority to mitigate or replace inappropriate offers by generating units in congested areas.
Thresholds have been established for the assessment and mitigation of locational market power in areas that experience congestion. The thresholds for acceptable conduct set under SMD recognize that areas with congestion pose a higher threat of negative market impacts and could unjustly increase costs in those areas. These thresholds determine when conduct is anti-competitive and can trigger immediate action by ISO New England. This action is designed to occur prior to the clearing of the market and thus to prevent unwarranted price increases in congested areas.
Market monitoring benefits the entire marketplace by continually evaluating market behavior and performance to ensure fair and competitive markets. When inefficient rules or anticompetitive behavior is detected, the market monitoring group acts to improve the rules or change the behavior. In known problem areas, market monitoring has the ability to immediately intervene in the market to prevent anti-competitive behavior.
This combination of approaches is designed to ensure that the markets running today work as well as possible, including areas where competition may be limited and that, in the long-run, the markets adapt and evolve to ensure continued reliability, competitiveness and efficiency.
Demand response allows users of electricity to be compensated for reducing electricity demand at times when the reliability of the system is at risk and during periods when wholesale electricity prices are very high. Reducing use during periods of high demand alleviates strain on the system and increases system reliability. Additionally, when system demand is high and prices rise, users may opt to conserve electricity, rather than consume it at the going price.
Demand Response Programs continue to play a critical role in New England under SMD. ISO New England will continue to offer its Price and Demand Response options to program participants opting to pla y a role in increasing system reliability. However, the creation of a multi-settlement system in New England provides program participants with a wider range of options to contribute to demand response initiatives. These programs are restructured to include demand response opportunities in both the day-ahead and real-time markets.
Energy conservation and Demand Response Programs are critical components to New England's wholesale electricity marketplace. Demand-side management helps to curtail demand when it is needed most and ensure a reliable electricity supply within the region.
