98 Evaluation Perspectives Customer Utility Regulatory

According to the U.S. Energy Information Administration, generation represents about 72% of the embedded investment in the U.S. electric power system. About 8% of the embedded investment is in transmission, and about 20% is in distribution. This being the case, it is no surprise that the primary attention in electricity policy discussions has been focused on generation. One key question is how utility-owned generation can co-exist in an effective competitive market. Depending on the state-by-state particulars, the evolving structure of the industry will heavily depend on whether utilities will be required to, or will voluntarily, structurally divest their generation. Major attention is also afforded to the questions related to transmission, particularly regarding investment concerns, structure, ownership, and operation.

DG is obviously focused on distribution, but it must compete with the economics and utility investment in conventional generation, transmission, and distribution. Although regulators have tended to focus most on the generation and transmission side of the business through IRP and the issuance of certificates of public convenience and necessity, regulators are likely to start shifting their concentration towards distribution. This is primarily due to the widespread agreement that there will be a continuing role for regulators to oversee the post-restructuring monopoly Discos.

Five nodes in an electric utility have been described by Joe Ianucci:*

• Distribution planning areas (e.g., ~150 megawatts)

• Distribution substations (~50 megawatts)

• Distribution feeders (~10 megawatts)

• Customers (one-third industrial at ~1 megawatt or larger; one-third commercial at ~100 kilowatts; and one-third residential at ~5 kilowatts)

These five nodes provide a basis for a discussion of DG evaluation perspectives. Ianucci states that there are two primary distributed generation evaluation perspectives: customer-centered and utility-centered. He is also of the opinion that the criteria used by the customer to evaluate DG contain the following: bill analysis/reduction, reliability enhancement, power quality improvement, cogeneration possibilities, distributed generation costs, capabilities, and operational difficulties. Added to this would be factors suggested by the Electric Power Research Institute: the cost of electricity that may be avoided by running the unit, fuel cost, installed cost of the system, and anticipated utilization of the unit (annual operating hours with an allowance for maintenance and outages) which would determine overall availability. Other important economic factors are net fuel rate of the equipment and maintenance costs (including spare parts, overhaul costs, and field service support). Labor costs to run the unit and utility standby fees also should be considered. Local utility tariffs may provide incentive to run or not run the unit depending on utility capacity requirements and market conditions.

The criteria used by the utility to evaluate DG contains the following: generation, transmission and distribution capital deferral/avoidance, system improvements (e.g., reliability) and problem mitigation (e.g., power quality), business implications (e.g., capital recovery), risk avoidance/managing uncertainty, customer partnerships (e.g., retention), DG costs, capabilities, and operational difficulties.

The criteria used by regulatory bodies will differ somewhat from state to state, but given the relatively common history and purpose of PUCs, certain expectations might be considered. The Regulatory Assistance Project has prepared a report** on distributed Resources for the Committee on Energy

* In his presentation to the Colorado Public Utilities Commission, November 14, 1999.

** Draft Report, "Profits and Progress Through Distributed Resources," July 15, 1999

([email protected]).

Resources and the Environment of the National Association of Regulatory Utility Commissioners. The key conclusions include the following:

The financial incentives favoring or disfavoring distributed resources deployment are generally unaffected by corporate structure. They are affected by the relationship between a utility's cost and price for distribution services. The location of the distributed resource is critical. Distributed resources installed on the utility side of the meter do not jeopardize profitability. The primary, and negative, impact on utility profitability of distributed resources deployment occurs when they are installed on the customer side of the meter. This is true for both demand-side and supply-side resources. From the utilities' perspective, demand- or supply-side resources installed on the customer side of the meter produce the same effect: sales go down and as a result revenues and profits go down.

Locating distributed resources in high-cost areas has significant potential benefits. The significant distribution cost savings resulting from distributed resources located in high-cost areas can reduce utility financial losses or even add to profits if the distributed resources are deployed only in high-cost areas.

The form of regulation also matters greatly, particularly whether the utility is subject to performance-based regulation (PBR) and, more importantly, whether the PBR is price- or revenue-based. Price regulation generally discourages distributed resources. Revenue regulation does not.

The deployment of distributed resources is affected by whether the utility has a fuel clause or similar regulatory provision; the nature of stranded cost recovery provisions, including the level of stranded costs, and stranded costs recovery mechanism (volumetric charges, exit fees, or other mechanisms that affect behavior); and whether there are balancing accounts for stranded costs.

Regulators have a number of policies available to align utility profitability with the deployment of cost-effective distributed resources. Some, such as revenue-based PBR, go directly to the heart of the problem and fix the way regulation works. Others, such as distributed Resource Credits, distributed Resources Development Zones, and placing restrictions on pricing flexibility, aim at making distributed resources profitable to utilities by trying to direct distributed resources deployment to high cost parts of the utility's system.

Getting utility profitability aligned with the deployment of cost-effective distributed resources is an important step, but it does not guarantee success. Even if regulation is able to completely align utility profits in the deployment of distributed resources, there may be other factors that overwhelm the power of any incentives. Such diversionary factors may include rate impacts, competitive and other risks, and issues of control or the lack thereof, each of which can undermine the incentives created in a PBR regulatory mechanism.

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