مکانیسم برد ـ برد برای تامین تجهیزات برق توسط یک شرکت توزیع محلی

A time-of-use rate option design allowing an LDC's customers to allocate their consumption to be billed at the fixed and daily-varying TOU rates offers a win–win mechanism for electricity procurement in the face of uncertain spot prices and hedging options. Even if all customers have the same risk preferences, the proposed mechanism is Pareto-superior to the tariffs and procurement strategies commonly used in North America.

Electricity market reform and deregulation have resulted in wholesale spot markets in Europe, Australia, New Zealand, and parts of North and South America.1 Spot electricity prices are inherently volatile with sharp spikes, thanks to daily fuel-cost variations, especially for the natural gas now widely used by the popular combined-cycle gas turbines; weather-dependent and time-varying demands that must be met in real time by generation and transmission already in place; unpredictable and random output from renewable resources (e.g., solar and wind); changes in available capacity caused by planned and forced outages of electrical facilities; price manipulation during generation shortages; precipitation and river flow for a system with significant hydro resources; carbon-price variations that affect thermal generation using fossil fuels; transmission constraints that cause transmission congestion and generation redispatch; and lumpy capacity additions that can only occur with long lead times.2 A regulated local distribution company (LDC) procures electricity from the wholesale market for resale to meet the demands of its retail customers.3 From a supply perspective, the LDC can mitigate its procurement cost risk by buying forward contracts, tolling agreements, and capacity options.4 From a demand perspective,5 the LDC can (1) offer reliability-differentiated tariffs that allow it to curtail sales when wholesale spot-market prices are high,6 and (2) implement real-time pricing that passes on the wholesale spot prices to its retail customers.7 To manage its portfolio of supply resources and retail sales, LDC management considers the tradeoffs between the procurement cost expectation and its variance.8 The optimal portfolio choice that drives the LDC's procurement plan, however, requires an assumption as to management's risk preferences,9 which may be open to debate and challenge. Even though the LDC may have been diligent in its procurement and risk management, it can still face the asymmetric risk of ex post prudence review by a regulator. 10 Under cost-of-service regulation, the LDC can at best recover its procurement spending. 11 If the LDC's hedging results in a large ex post loss, the regulator may disallow its recovery, thus harming the LDC's earnings. To minimize the risk of ex post cost disallowance, LDC management may decide not to hedge. Such a strategy, however, can backfire. Under cost-of-service regulation, the LDC can at best recover its procurement spending. In a rapid price escalation environment, a regulatory lag may cause the spot-market purchase cost paid by the LDC to far exceed the bill payments made by its customers, translating into a large loan from the LDC to those customers. If disallowed by the regulator, the unpaid loan can bankrupt the LDC.12 In response to the spot- price volatility and spikes, the regulator (e.g., the California Public Utilities Commission) may require forward contracting by the LDC for the bulk (i.e., 95 percent) of its retail sales.13 While the regulatory requirement may be justified by the presumption of customer preferences for known and stable rates, it is economically inefficient if some customers do not desire fixed prices for the bulk of their consumption. This article presents an electricity procurement mechanism developed by a California-based contract-research firm that focuses on energy-related issues, for its local distribution company (LDC) clients. The mechanism integrates and extends studies done for LDCs in California, the Pacific Northwest, Florida, Missouri, British Columbia, and Israel in connection to electricity-rate options, electricity portfolio management, and procurement-cost recovery. It shows that even if an LDC's customers have identical risk preferences, the LDC can implement a win–win mechanism for electricity procurement in the face of uncertain spot prices and hedging options. Enabled by smart meters that record hourly consumption by each customer as part of the smart electricity grid initiative,14 the mechanism integrates Pareto-superior time-of-use (TOU) rate options15 into electricity portfolio management.16 Since the mechanism induces the customers to reveal their preferences for fixed vs. daily-varying TOU rates, it helps determine the LDC's customer-driven procurement plan. Since the LDC's procurement plan is driven by customers’ self-revealed preferences, it preempts the need and reason for ex post prudence review by a regulator.

Recognizing that wholesale spot-market prices are highly volatile, we propose a TOU rate option design that allows an LDC's customers to allocate their consumption to be billed at the fixed and daily-varying TOU rates. The customer-chosen allocations inform the LDC as to the amount of electricity to be bought from the forward market. Even if all customers have the same risk preferences, our proposed mechanism is Pareto-superior to the tariffs and procurement strategies commonly used in North America. Since the LDC's procurement plan resulting from the mechanism is driven by customers’ self-revealed preferences, it preempts the need and reason for ex post prudence review by a regulator. We would be remiss if we fail to discuss future extensions of our proposed mechanism. First, the quarterly tariff update can be made into a menu of update frequencies for customer self-selection. For instance, a customer may choose to have monthly, bi-monthly, quarterly, semi-annual, or annual updates. The update-frequency choices are largely limited by the LDC's tariff administrative cost and the forward market's trading and price discovery. Second, the LDC may allow its customers to have different α allocations by TOU period. At no cost to the LDC, this extension gives more flexibility to customers in their management of electricity cost expectation and risk. Finally, the LDC may expand the set of TOU tariffs with a different number of TOU periods. This extension aims to reflect the presence of multiple spot markets. For example, California has, besides bilateral trading of on-peak and off-peak electricity, an hourly energy market operated by the California Independent System Operator that daily yields 24 hourly prices. The LDC may offer four TOU tariff options: (1) fixed on-peak and off-peak rates; (2) variable on-peak and off-peak rates; (3) 24 fixed hourly rates; and (4) 24 variable hourly rates. To conclude, the LDC can exploit an advanced metering infrastructure's metering and billing capabilities to offer a wide spectrum of TOU tariff options that its customers can self-select for their electricity cost/risk management. The customer preferences thus revealed will ensure the LDC's prudent procurement, thereby ensuring the LDC's cost recovery.