بازارهای انرژی عمده فروشی: تنظیم چارچوب های مناسب برای تقاضای پاسخگو قیمت

Market-based dynamic pricing, or price-responsive demand, has the potential to bring the energy industry a step closer to what was envisioned at the time of restructuring, by shifting incentives for resource adequacy investments to energy markets. This fundamentally requires a reform of wholesale energy markets and resource adequacy mechanisms so that they recognize the impact of future PRD from the onset.

In the U.S., the benefits from energy market reforms initiated more than a decade ago are now widely recognized. The implementation of ISO-operated bid-based generation markets in the late 1990s led to greater transparency in regional prices for energy, serving as a benchmark of the opportunity costs of bilateral transactions within a region and across geographical boundaries. Yet a number of key challenges prevail. Wholesale market designs continue to be constrained to varying degrees by regulatory measures, environmental policies, and technological barriers. Market participants are currently operating under a mix of market-based energy incentives and regulatory-influenced capacity prices. In this regard, the U.S. is no different from many other restructured energy markets in the world. To fully reap the potential efficiency gains from restructuring, additional work is needed to improve pricing mechanisms at both the wholesale and retail levels, involving both federal and state regulators. A. Smart Grid and its potential to improve the existing market designs Smart Grid technologies are bringing about fundamental changes to the energy industry. The term smart grid encompasses a number of advanced, digital technologies such as smart metering, high-performance line sensors and advanced measuring and communications, all of which enhance the ability of transmission and distribution system operators to ensure a more efficient and reliable provision of electricity. Smart meters are able to record usage in hourly or 15 minute intervals and are deployed along with two-way communications, allowing the utility to read loads remotely as well as to capture and store detailed energy-usage data using digital technology. To date, smart meters have been installed on a large scale in California, Florida, Georgia, and other states are planning full deployment over the next few years. A number of countries around the world, including Italy, Spain, Sweden, and Finland, are also at advanced stages of smart metering deployment. With the increased availability of smart meters, there are fewer reasons not to revamp retail prices so that they are more reflective of market prices. The notion is that by giving all electricity consumers a chance to see, respond to, and influence market clearing prices or locational marginal prices (LMPs) on an hourly basis, energy markets will be able to reduce the overall costs of electricity service. Retail market-based rates, when properly designed, can bring important efficiency and reliability benefits. As more consumers face economic incentives for market-based demand response on a day-ahead basis, the ISO should be able to rely less on costly “day-of” emergency calls. In addition, dynamic rate designs combined with automated technologies can contribute to reduce the cost of ancillary services. This is particularly important at a time when system operators need more flexible resources to keep system reliability intact, in presence of large volumes of wind and solar intermittent output. Rates can directly provide customers with incentives to “store” electricity when system demand is low and reduce load when the system has less available capacity. It is possible to design dynamic rates that preserve not just efficiency goals but also equitable allocations of costs among consumers. Despite the progress in deployment of smart meters, only a marginal amount of consumers are currently under dynamic rates.1 The reasons for this range from public inertia to mistrust of the impact of smart rates and time-varying rates on consumers, who have largely grown accustomed to paying fixed electricity rates. There have also been arguments that these rates might prove inequitable for smaller, low-income users. Yet it is possible to design dynamic rates that preserve not just efficiency goals but also equitable allocations of costs among consumers. Fortunately, the mind-set across the country is largely shifting thanks to the proliferation of government-funded dynamic Smart Grid pilots in the last few years, which have generated very positive results.2 For economists and energy policymakers, the expansion of dynamic retail pricing presents an extraordinary opportunity to revisit the rationale of the existing wholesale market design. Every regional transmission organization (RTO) and independent system operator (ISO) has been forced to juggle a myriad of regulatory constraints when operating the wholesale markets. Many, if not all, of these market design elements developed over the years, in large part to counteract the lack of retail dynamic pricing. The implication is that electricity generators in most markets are not able to solely rely on expectations of market energy prices to guide their decisions to enter, stay, or leave the market. Any administrative parameters affecting the design of the markets are subject to changes by FERC, which naturally brings uncertainty to market players and increase the risk premium that generators demand for entering the market. Transient price spikes above the variable costs of the marginal generating unit in the dispatch stack do not necessarily mean that such generators have engaged in economic withholding or abuse of market power. Market power can be defined in several ways but it is essentially the ability of a generator to increase market energy prices above short run marginal costs and to sustain prices at that level. In the US, soon after it became obvious that inelastic demands could do nothing to prevent large price spikes, FERC required ISOs to adopt stringent price caps and offer caps, effectively precluding the ability of generators to submit offer prices above their opportunity costs.3 As a result, market prices in most US regions are not allowed to exceed $1,000/MWh, with the exceptions of the Electric Reliability Council of Texas (ERCOT), where the market price cap is currently at $4,500/MWh. ERCOT is currently in the midst of discussing options to increase the price cap in an effort to support resource adequacy. Price caps in the U.S. differ largely with those employed in other markets around the world, such as in the Australia National Electricity Market (NEM), where generators are allowed to bid as high as AUD$12,900 (approximately US$13,450/MWh). The capacity markets implemented in the various U.S. markets to compensate for the lack of scarcity rents in energy markets have been improved over time, yet they are a second-best solution and as such present challenges in their own right. They have a limited role in providing scarcity price signals to consumers in near-real time conditions, either region-wide or locally. Forecast assumptions on weather, demand, or generation or transmission outage data used when setting capacity requirements may not hold on a particular day or in a particular year. This lack of a transparent, dynamic market value of reliability is an important drawback when it comes to provide appropriate incentives for price-based response. Capacity markets and in particular capacity auctions are also vulnerable to market power by both generators and buyers of capacity resources. The various parameters employed to address those concerns – such as the choice of a forward-looking horizon, offer caps, price floors, and related measures – influence the resulting price which may not be commensurate with the actual conditions of capacity surplus in the system in a given year. Changes to existing market rules will be needed to accommodate the new dynamic rates, and their impact on daily loads. The expansion of price elastic demands enabled by smart meters can dramatically affect most if not all of these regulatory elements, including the level of (and need for): (1) market offer and price caps that serve to mitigate market power; (2) out-of-market mechanisms that compensate resources in exchange for addressing short-term system contingencies; (3) the prescribed manner in which utilities or load-serving entities (LSEs)4 must procure capacity for their customers, and (4) federal or state-approved regional reliability targets, which currently may bear little or no relationship with the overall users’ willingness to pay for electricity. Overall, the industry faces a complex task. Changes to existing market rules will be needed to accommodate the new dynamic rates, and their impact on daily loads. At the same time, the reforms to the regulatory framework required to capture the predicted efficiencies from smart metering may take some time to materialize. Regulators and ISOs may not be ready to trust emerging technologies that have an impact on system reliability, particularly given the limited history with dynamic pricing for the mass market. While gradualism in market rule changes may be required, it is important to set the basic framework for efficient dynamic pricing or price-responsive demand to materialize from the onset. The first task is to undertake a comprehensive review of the wholesale market design and retail ratemaking policy elements that will need to change to maximize the potential gains from PRD. The second task is to decide the specific policy revisions that may guarantee efficient of price-responsive loads, accounting for existing options to monetize load reductions in wholesale and retail markets. The goal is to streamline the current set of incentives while enabling a transition to a more lightly regulated wholesale market environment.