مزایای مشارکت مشتری در بازارهای عمده فروشی برق
|کد مقاله||سال انتشار||تعداد صفحات مقاله انگلیسی||ترجمه فارسی|
|3023||2002||11 صفحه PDF||سفارش دهید|
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Publisher : Elsevier - Science Direct (الزویر - ساینس دایرکت)
Journal : The Electricity Journal, Volume 15, Issue 3, April 2002, Pages 41–51
By participating in the New York ISO’s price-responsive load programs, customers have contributed importantly to the prevention of forced outages at a time when system electricity demands hit record levels. Through their load curtailments, they also exerted some downward pressure on market prices and price volatility.
Most would now agree that wholesale electricity markets need the discipline that can only be possible by allowing customers to respond to wholesale prices.1 Customers must be coaxed away from the safety of conventional, hedged retail services and be provided with sufficient incentive to accept the risks inherent in wholesale market price volatility. Standard offer services in competitive retail markets remain highly hedged, partially to secure the collection of stranded assets. New competitive retailers feature various hedging products in response to what they hear from customers. Moreover, legacy load management programs that provided some semblance of price responsiveness under regulated market regimes have fallen victim to the new market order. The value of legacy load management programs, which were based upon an individual utility’s avoided costs, is eroded substantially when regional transmission organizations (RTOs) are instituted. So far, any potential market influence of customer price responsiveness remains largely untapped. Some have prescribed an extreme remedy: make the standard retail offer some variant on real-time pricing, thereby forcing customers to confront wholesale market price volatility head on. While most customers will continue to seek the safe harbor of a hedged price, a small fraction will likely find that they can lower costs by avoiding high prices through effective load management. In the end, customers will assume the degree of risk that fits their circumstances and in the process exert the appropriate influence over market price. While this extreme remedy may eventually bring about this desired result, customers may at first rush to a hedged service to avoid those risks, leaving price volatility unabated. An alternative remedy is to offer customers limited and highly structured opportunities to participate in wholesale markets through price-responsive load (PRL) programs managed by independent system operators (ISOs) and RTOs.2 By scheduling or dispatching PRL resources, the ISO can ensure that these resources are deployed when their value to the market is highest. During the summer 2001, the New York ISO’s (NYISO’s) Market Members elected to implement two pilot PRL programs that are consistent with this alternative view. In what follows, we review these PRL programs briefly, outline the several categories of PRL program benefits, and provide an empirical assessment of the program effects during the summer 2001.
نتیجه گیری انگلیسی
Based on our program evaluation, it is evident that customers have been able to gain some access to New York’s new wholesale electricity markets through participation in the NYISO’s PRL programs. In doing so, these customers, in cooperation with the NYISO, have contributed importantly to the prevention of forced outages at a time when system electricity demands hit record levels. Through their load curtailments, they also exerted some downward pressure on market prices and price volatility. If active participation in DADRP were expanded significantly beyond the first year’s subscription rates, these customers could force even greater discipline on the DAM. Since load scheduled in DADRP is not served in real time, this added discipline may also be reflected through lower prices in real time and fewer EDRP emergency events. In our evaluation, we have discussed the PRL program effects from both a short-term and long-term perspective and they are summarized in Table 8. Both programs delivered benefits in excess of the direct payments made to participants, even under the most conservative assumptions about their impact on the market. EDRP resources proved to be as valuable as their generation resource counterparts in protecting customers service reliability, and they appear to have provided an additional benefit in abating extreme price volatility that often accompanies system emergency states. Load curtailments through the DADRP program, which were paid the fair market value their generation counterparts receive, provided benefits over and above those the participants realized directly. A little price-responsive load can go a long way toward reducing prices and price volatility when it is fully integrated into the ISO’s pricing and scheduling operations. Table options 1 Theresa Flaim, The Big Retail “Bust”: What Will It Take to Get True Competition? Elec. J., Mar. 2000, at 41–54; Douglas Caves, Kelly Eakin, and Ahmad Faruqui, Mitigating Price Spikes in Wholesale Markets through Market-Based Pricing in Retail Markets, Elec. J., Apr. 2000, at 13–23; Eric Hirst, Price-Responsive Demand in Wholesale Markets: Why Is So Little Happening? Elec. J., May 2001, at 25–37. 2 The NYISO, like its Northeast counterparts, operates spot energy markets that facilitate the direct integration of PRL resources into market transactions, thereby receiving full market value. The same result can be achieved in self-scheduled markets, like that of the Electric Reliability Council of Texas (ERCOT) ISO, by allowing qualified PRL resources to count toward LSEs’ generation scheduling obligations. 3 To supplement or fulfill their EDRP curtailment intentions or obligations, customers may use on-site backup generation. 4 The NYISO allows load-serving entities to claim curtailable special case load resources (SCR) to fulfill their installed capacity (ICAP) requirements. Customers that qualify their load curtailment capability can sell their ICAP/SCR capacity, which generates a stream of payments. The NYISO exercises its demand call on ICAP/SCR during periods of reserve shortfalls. Participants in ICAP/SCR receive up-front payments that PRL program participants do not. The up-front payments appeal to many customers in spite of the penalties assessed for non-compliance in the ICAP/SCR program. 5 See, for example, Robert Chambers, Applied Production Analysis: A Dual Approach (Cambridge, UK: Cambridge University Press, 1988), and W.E. Diewert, Applications of Duality Theory, in: M.D. Intriligator and D.A. Kendrick (eds.), Frontiersof Quantitative Economics, Vol. 2 (Amsterdam: North-Holland, 1974). 6 See, for example, William Tomekand Kenneth Robinson, Agricultural Product Prices, 2nd ed. (Ithaca, NY: Cornell University Press, 1981). 7 The logic of this specification is consistent with other studies that have estimated input demand and output supply functions based on equilibrium prices and quantities generated from programming algorithms. See, for example, Paul Preckel and Thomas Hertel, Approximating Linear Programs with Summary Functions: Pseudo-Data with an Infinite Sample, Am. J. Agric. Econ., 70, 1988, at 398–402, and James Griffin, Long-Run Production Modeling with Pseudo-Data: Electric Power Generation, Bell J. Econ., 8, 1977, at 112–127. 8 Price data and data on system-wide generation availability are publicly available on the NYISO Web site. Load data by zone are similarly available, but with a 6-month lag. For this analysis, the NYISO made some still-confidential load data available as well as some data on transmission line congestion. 9 Points at which the regimes change are called “knots,” and for consistency the functional values must be equal coming into and going out of these knots. To see how this is accomplished through variable transformations in an OLS regression model, see Amy Whritenour Ando, The Price-Elasticity of Stumpage Sales from Federal Forests, Discussion Paper 98-06 (Washington, DC: Resources for the Future, Nov. 1997). 10 For a more thorough analysis of outage cost estimates, see Ray Billinton, Economic Cost of Supply, Proc. IEEE, Jan. 2002. 11 EDRP resources are dispatched by the NYISO when and where it anticipates operating reserve shortfalls. At times, load pockets arising from transmission constraints necessitate evaluating regional needs and dispatching EDRP curtailments accordingly. This was the case on Aug. 10, when Western New York was excluded. 12 One explanation for the high degree of persistence is that those EDRP customers that also were subscribed to the ICAP/SCR program faced non-compliance penalties for most of these hours, since the ICAP curtailment option had been coincidently exercised by the NYISO. However, this is not a complete explanation since only 40 percent of PRL participants jointly subscribed to PRL and ICAP/SCR. 13 The amounts reported are those paid by the NYISO to LSEs, CSPs, and direct serve customers. The latter obviously received the full amount. LSEs, operating under standard offer tariff provisions, paid 90 percent of program benefits to participants. CSPs did not report the terms of their benefit sharing arrangements with customers, but the standard offer 90/10 split likely influenced CSPs’ deals. 14 The 25 percent improvement reflects the average conditions in an hour typical of many of those during which EDRP was called. 15 While it is tempting to compare the collateral benefits with the payments to participants in order to construct a benefit/cost test, such a comparison is not appropriate. The collateral benefits reflect transfers from generators to LSEs and possibly eventually to retail customers. Improved reliability does improve welfare, and does lower price volatility. 16 Price effects are calculated for the hours from 6 a.m. to 10 p.m. during weekdays in August. These results were derived using monthly zonal prices as posted by the NYISO and the LBMPs reconstructed using the estimated zonal supply flexibility relationships. 17 Hedging benefits were derived assuming that 40 percent of all load requirements of LSEs were purchased in the DAM, which corresponds to the current average level of such purchases across the state. 18 Participants bid DADRP resources identical to the way generators bid conventional resources. Hourly DADRP bids can be partitioned into sequential blocks of successively higher strike (curtailment) prices, and bidders may specify minimum runs times and curtailment cost guarantees that in effect allow participants to bid continuous strips for curtailment, on an all or nothing basis. 19 DADRP customers are allowed to bid start-up (more appropriately outage) costs, along with the energy price. Their bids are evaluated on an equal footing with generators’ bids in the dynamic programming part of SCUC. When both start-up costs and energy costs are considered jointly, they clearly were a cheaper source of energy than competing generators. 20 At the time this analysis was completed, the settlement data for DADRP had not been fully processed by NYISO. Therefore, the program costs provided assume that DADRP curtailment payments were equal to LBMPs in the DAM, and for this reason, they exclude any startup costs included in customers’ bids that were accepted. Actual DADRP payments will likely be higher by 20–30 percent.