Distributed Energy: Capturing the Benefits of Regional Demand Response
The problem is that the transmission system was designed and implemented to deliver generation to its own load centers and is not able to deliver the lowest-cost generation to the highest-paying market.
Part of the Federal Energy Regulatory Commission's (FERC) solution to congestion is locational marginal pricing (LMP), which is instituted by regional transmission organizations (RTOs) and independent system operators (ISOs). LMP and other congestion management tools, such as financial transmission rights, are designed to assign ensuing costs to those that cause congestion and to protect those that don't.
FERC's latest position on wholesale markets, according to the Wholesale Power Market Platform White Paper issued in April 2003, recognizes that demand response to increasing price is a necessary part of the spot market for wholesale prices. In other words, if prices rise steeply in an area, electricity demand should decrease, thus reducing price volatility by lowering the load served. In states that have deregulated retail markets, demand-response programs are planned to be overseen by the RTOs and the ISOs. In states that do not, FERC strongly advocates demand-response implementation by state regulators.
The crux of all of these possible programs applies directly to distributed-energy (DE) applications. These can provide an easily measurable and verifiable manner to deliver demand response. In addition, DE applications can become more cost-effective in regions where demand-response values can be added to other DE benefits that can be captured.
DE Boosts Demand Response
DE applications can include a wide variety of small-scale generation, energy storage, or demand-side management technologies. Technologies other than engine-generators, such as microturbines, energy storage, or demand-side control, also could be capable of delivering demand response. A typical DE application might be a commercial or small industrial customer wanting improved, local supply reliability from a backup generator.
In implementing demand response, RTOs and ISOs in most regions have allowed customer-site generation to provide demand response along with other energy-reduction techniques. The rationale behind this is that customer generation looks like lower energy use on a constrained transmission network. The generation will reduce the spot price in the locational, wholesale-market-constrained area, but the generation still can earn payments substantially higher than costs through demand-response payments. The customer typically receives the market price for output, and these revenues can reduce the overall costs to provide local reliability.
For the following, the primary focus will be on traditional generation technologies, fueled by natural gas and ranging in size from 100 kW to 5 MW.
Customer-located generation can qualify for several types of demand-response programs. For example, in the New York ISO (NYISO), DE generation can participate in three programs: an installed capacity market (ICAP), an emergency capacity program, and a day-ahead energy program.
The ICAP market allows DE to bid into the region's capacity-supply market where prices are based on location. Historically ICAP payments have been high, especially in New York City. The emergency capacity program allows DE placed in strategic locations to capture high prices when there is a reliability issue. The day-ahead energy program is perhaps the most complex demand-response function to perform because daily operations likely would be needed to bid in the day-ahead market.
The typical approach begins each morning when the demand-response operator is bid into the spot market run by the ISO over a Web-based connection. Various bidding strategies are used to ensure that costs are met if called on to generate. Overall the bidding process is a "Dutch Auction," whereby the ISO stacks up bids in bidding-order to serve the load. All providers are paid the same price given to the last increment of supply. Demand-response bidders are taken into account and will be called on to generate if the price is competitive.
Programs and features from existing RTOs and ISOs are summarized (see sidebar chart).
A Prime Example
DE applications that provide backup for local reliability easily can be upgraded for paralleling operation with the grid and remote–command and control at relatively low cost. Using natural gas helps, but it also eliminates emission requirements in some locations.
To measure the impact of the improvement in cost-effectiveness that could be seen under favorable demand-response conditions, a simple example is presented. Table 1 summarizes an annual cost of about $88,700 per year (equivalent to an approximate annual capital cost of $350,000) for a 1-MW generator system that provides backup supply and also is operated in the New York ICAP market. It is assumed that the NYISO asks for generation for two events during the year. The annual cost components are debt service, fuel, and operations and maintenance (O&M).
Table 2 summarizes the income potential through the ICAP market at three locations—in New York City, in Long Island, and throughout the rest of the state—based on the 2002–2003 bid prices. The ICAP market provides needed capacity for those load-serving entities that are short in supply. The New York City summer capacity value was more than $11/kW-months for the six-month season. When called on to generate for reliability, the DE facility receives an energy payment, often in the neighborhood of $500/MWh, for an eight-hour period.
At the New York City location, the annual ICAP payment based on actual 2002–2003 prices results in revenues greater than annual costs by some $32,000. For the Long Island location, the payments are not as great, but costs are reduced by some $64,000. For the rest of the state, the costs are reduced by about $22,000.
Hours of operation Two- to eight-hour events/year, $500/MWh strike price
No property or income taxes considered, assumes no siting or emission roadblocks.
Value and revenue streams Provides backup supply and bids into New York ICAP market on a six-month basis
This example illustrates that in such locations as New York City, current demand-response payments might completely pay for backup generation—even generate a return. Other regions are not as attractive, but operating as demand response substantially could reduce annual costs of backup generation.
With such numbers as those in this example, it is difficult to see why these programs are not heavily employed; however, there are a couple of issues that hold back decisions on what could look to be a great investment. First, the managers of commercial or small industrial customers might not be well informed about these programs. Second, there is the issue of how such customers could handle price risk and operational requirements; for example, the New York ICAP prices could be high this year but low next year.
Case Open to Possibilities
The business case for DE as part of the nation's demand response has not been fully developed, nor has the opportunity been fully communicated to all potential parties. New York has made substantial progress in these activities, but power supplies have been especially tight in the Northeast for years. The push for development of emergency curtailment and price-responsive programs came from stakeholders, state agencies, and NYISO. Overall, New York has taken a strong regional approach that might or might not produce similar results in other parts of the nation.
New York has provided some valuable lessons. First, DE technologies are mature enough to provide power reliably in magnitudes large enough to benefit the region. Also, control/dispatch technologies are up to the task of dispatching, and pricing and accounting mechanisms are in place in making settlements. NYISO and other ISOs can provide pricing history data for use in feasibility studies of the DE application. This is primarily LMP, but other prices, such as ICAP, which are transparent to a customer, can be used.
Many, including state regulators, technology companies, and even several advocacy groups, are helping to establish effective demand-response capabilities. One difficulty in developing a business case or model, however, is the lack of a national approach to demand response. Different RTOs, utilities, and states can approach demand response differently. FERC, however, has the ongoing responsibility in wholesale markets, seems to be taking demand response as a serious and valuable program, and is looking closely at RTO and ISO tariff filings.
One key issue that needs to be addressed in a business model is the reluctance of commercial and small industrial customers to tackle the intricacies of demand response when it is outside of their core business line and competency. This includes making decisions where there is a market price risk in energy or demand and tough credit policies.
Some approaches are available to address this need. First, the program design could be relatively risk-free, and penalties for nonperformance of individual participants could be small. With multiple participants, the RTO could design the program to meet its reliability needs and still have clear price signals. A second approach could be for customers to engage third-party providers of expertise, risk mitigation, operational support, and even capital in partnership with electricity customers. These companies could evolve from energy service companies or they could be new startups; in any case, they are only beginning to emerge. Certainly a viable third-party industry will be a key component to widespread adoption of demand response.
Author's Bio: Lynn Coles is a senior director for R.W. Beck in Indianapolis, IN.