Presenting a fair and simple distributed generation plan for utilities and policy-makers.
Distributed generation (DG) continues to face many institutional barriers erected before the technology emerged as an economic alternative. Chief among these barriers are existing rate and regulatory regimes, which fail to offer appropriate incentives to utilities and customers who might otherwise substitute DG facilities for distribution and generation.
DG as discussed here refers to small electricity generation facilities, up to 50 MW, located on the distribution system close to the point of consumption. DG facilities include micro-turbines, fuel cells, internal combustion engines and small gas turbines. These frequently are combined heat and power facilities.
This article addresses the rate treatment accorded these facilities and discusses changes that will enable distributed generation to compete head-to-head with traditional distribution facilities and central station generation, purely on the basis of the relative economics of each. Accordingly, rate proposals focus on methods that provide incentives to customers and utilities to install DG facilities whenever those facilities make economic sense.
To begin with, policy-makers must establish zonal credits. For example, when it does make economic sense, distribution utilities should be challenged to engage in a "localized" least-cost planning process for their distribution facilities. The process would be comparable to generation least-cost planning, establishing zones in which installation of DG facilities would be encouraged through the provision of credits that recognize the benefits provided to the distribution system by these facilities. These credits should be available to any customer that installs the facilities in a DG zone. A utility should be allowed to install facilities in a DG zone and be entitled to recover in its distribution rates the capital and operating costs of the facility (subject to crediting of the generation-related revenues from the DG facility).
In addition to rate issues, numerous other important regulatory and institutional issues must be resolved before distributed generation can compete with distribution and generation on a fair, unbiased basis. These problems include interconnection procedures, the role of standardized versus negotiated contract terms, payments for ancillary services, stranded costs, and the transmission and distribution losses applied to DG sales to others.
Valuable ancillary benefits of DG include voltage and frequency support, voltage regulation, enhanced reliability, ability to provide both heat and power, and emission reductions. It is important to accurately estimate the value of these benefits, and design pricing systems to flow the benefits through to owners of distributed generation facilities. The associated issues are complex and their resolution is being discussed throughout the industry.
DG: Economics Should Be the Guiding Principle
Two tenets of equity and economics should govern the regulation of distributed generation facilities. First, the regulatory system should be neutral. It should not be artificially tilted toward or against customer-owners of DG facilities. Likewise, it should not incorporate measures that overly encourage or discourage utilities to invest in these facilities. Fairness is the goal.
Second, the regulatory system should be simple. Distributed generation facilities are by their nature small. Prospective DG owners cannot afford to navigate complex regulations or engage in protracted negotiations with utilities. Moreover, complex regulatory systems are too easily manipulated. Today, the regulation of DG fails these two tenets: It is neither neutral nor simple. Furthermore, distribution costs vary geographically, but distribution rates do not. The capital costs of new and upgraded distribution facilities vary widely from one geographic area to another.
Despite this variation, for social and political reasons, the typical distribution company's rates are uniform over its entire service area. In a classical distribution monopoly setting, this geographic uniformity has no effect on competition because there is no competition. However, with the advent of DG facilities, this geographic uniformity stifles beneficial competition from DG, increasing the costs and reducing the efficiency of the electric system.
Many DG facilities that should be installed in lieu of distribution facilities in areas where there are high distribution costs are not installed simply because of artificially low retail prices faced by the prospective DG owners. Stripped to the economic fundamentals, the DG facility is the preferred option. But, cloaked by regulatory distortions, uneconomic distribution facilities are built instead.
The solution is geographically de-averaged prices-or credits-for distributed generation. It is politically infeasible to eliminate the geographic uniformity of distribution rates. The price increases for customers in high-cost areas would be excessive. This very political impossibility highlights the benefits that would accompany strategically placed distributed generation facilities.
Nevertheless, there is a method of harnessing the existing cost disparity to enable the installation of economic distributed generation. Specifically, states should implement a system of zonal crediting for DG facilities in which facilities are effectively confronted with the true geographic dispersion of costs. This crediting mechanism effectively "de-averages" distribution costs and benefits all parties-the distributed generation owner, the utility and other retail customers.
Establishing Distributed Generation Zones
Distribution companies should be required to establish distributed generation zones through a localized least-cost planning process administered by the state utility commission.
Generally, distributed generation zones would coincide with portions of the distribution system that are either congested or experiencing customer growth, calling for enhanced or expanded distribution facilities. Not unlike traditional least-cost planning processes focusing on the production plant, the utility would be asked to submit its distribution plan for consideration by the state utility commission biennially. The localized least-cost plan would compare on a zonal basis the cost and benefits of projected distribution facilities against the capital and other operating costs and benefits of distributed generation to determine the least costly alternative.
The plan should recognize the ability of new DG facilities to allow the utility to defer the construction of new or upgraded facilities or to replace some or all of the facilities with distributed generation technologies. On the basis of the least-cost plan, the state utility commission would delineate as distributed generation zones those portions of the distribution system in which deferral or replacement benefits are attractive.
The deferral benefit equals the difference between the net present value of the cost of constructing distribution facilities now and constructing them later. The capital replacement benefit is the net present value of the construction cost of the facilities that DG would replace.
A customer would be eligible for a zonal credit only if the customer installed DG in a distributed generation zone. A utility would be required to install DG only in distributed generation zones in accordance with its least-cost plan.
Conceptual Dichotomies That Prove Useful in Pricing DG
In assessing any pricing system for distributed generation, two conceptual dichotomies prove useful. First, profound differences arise depending on whether the DG resides on the customer side of the meter or the utility side. On the customer side of the meter, DG competes with the distribution "natural monopoly" and, under currently prevalent cost-of-service rate regimes, threatens utility revenues. Moreover, when the customer owns the DG facility, the lion's share of the benefits accrue to the customer rather than to the utility. As a consequence, in the absence of regulatory intervention, utilities will, in their own rational self-interest, erect barriers to the entry of DG. The types of barriers primarily include complex and costly interconnection procedures and requirements and high "standby" rates.
By contrast, on the utility side of the meter, in a properly designed regulatory regime, the utility can substitute DG for higher-cost distribution facilities, sell the output of the facility, and enjoy the ensuing financial benefits.
Currently, however, prevalent forms of rate design and restrictions placed on utilities in competitive markets frequently eliminate the utility's ability to profitably employ DG facilities. As a consequence, the utility's use of socially beneficial distributed generation is relatively rare today.
The second useful conceptual dichotomy relates to industry structure. A utility that has been unbundled into generation, transmission and distribution components in a jurisdiction with retail competition operates under a profoundly different, more complex regulatory regime than does a vertically integrated utility in a traditional, non-competitive environment. Unbundled utilities frequently face ownership and operation restrictions on the relations between their distribution and generation arms that preclude the distribution arm from owning DG facilities.
Distributed generation incorporates attributes of both distribution and generation. If the utility is forbidden to combine them, DG is not an option for the utility no matter how economic the facility may be. By contrast, a vertically integrated utility can view the economics of DG facilities in their totality, comparing the cost of prospective facilities with the combined costs of the generation, transmission and distribution facilities that the DG would replace.
This article enunciates the basic principle that the regulatory system should be neutral as to the ownership of the DG facility. However, DG facilities today are more commonly owned by end users than by utilities. We now address distributed generation facilities that are owned by utilities and installed on the utility side of the meter, either within a distribution substation or near to a customer's load.
Regulated utilities have an obligation to serve new distribution customers and meet increased loads in their franchise service areas. If the regulator provides comparable regulatory treatment to DG facilities owned by a utility and the utility's traditional distribution facilities, then the utility can make an efficient economic choice between the two options. The challenge for policy-makers is to level the playing field.
Incentive rates in the form of a price cap or a revenue cap can provide utilities strong incentives to invest in DG on the utility side of the meter. For a utility with a price cap or revenue cap in place, reduced costs translate into increased profits. It follows that, unless regulations are artificially skewed in favor of DG facilities, the utility will compare its cost of expanding its distribution facilities to its cost of installing DG and choose the lowest-cost option to maximize its profit.
Meanwhile, a vertically integrated utility that installs DG enjoys a variety of benefits. In addition to reducing its need for new distribution facilities, utility installation of DG avoids transmission and distribution energy losses, reduces the need for central station or purchased power, and reduces the need for transmission capacity. Some of these avoided costs, such as transmission facilities, are lumpy in nature, so, for example, one small DG unit obviously will not eliminate the requirement for a new 765-kV transmission line. Just as obviously, a sufficient mass of DG facilities will reduce today's pressing need for substantial transmission investment.
The utility should be required to engage in a localized least-cost planning exercise. The exercise would compare the costs and benefits of the DG unit(s) to the sum of all of the avoided costs and benefits it would receive from reduced investment and operating costs in distribution, central station generation, and purchased power and transmission. At the conclusion of the localized least-cost planning procedures, the utility should choose the lowest-cost option.
Unbundled Utilities
The state of affairs for unbundled utilities contemplating the purchase of DG units is more complex than for vertically integrated utilities. This applies to all unbundled utilities, albeit with differing degrees of emphasis, depending on the degree of competition the utility faces and the format of its structural or functional separation.
Distributed generation embodies aspects of both generation and distribution, but the utility's generation and distribution operations are separated. While it is eminently sensible to closely monitor the relations among the various marketing, wires and generation arms of a utility, such regulation need not preclude the use of DG by an unbundled utility.
Furthermore, an unbundled utility should be allowed to recover the cost of DG facilities through its rates, with an appropriate crediting of generation-related revenues. Under this mechanism, the utility would place the capital cost of the DG unit into its rate base, recover operating costs on a flow-through basis, and credit all generation-related revenues to the cost of service. The generation arm of the utility should be allowed to sell the output of the distributed generation unit subject to the restrictions that apply to any other of its generation sales. In this manner, the regulatory process would be neutral between both utility and non-utility DG and between DG and distribution facilities. Meanwhile, on the customer side of the meter, a customer installing distributed generation facilities should receive a proportionate share of the credits established for the zone in which its DG facilities are being installed.
The Details: Calculating Zonal Credits
The first step in the calculation of zonal credits, akin to the traditional rate-making exercise of setting the revenue requirement, is to establish for each zone the total amount to be credited to entities that install DG in the zone. This amount should be the sum of the deferral and replacement benefits in the particular DG zone, which represents the "pot of dollars" that these projects in the zone will make available to society. By dividing this pot of dollars in an equitable manner, utility shareholders, utility customers and DG developers can all benefit. If the benefits of DG are not divided among the interested parties, utilities will have no incentive to calculate accurate zonal costs and, in fact, will have a powerful incentive to estimate inaccurate costs. Consequently, developers will face artificially diminished incentives to install new DG facilities. Distribution system costs will increase needlessly.
The next step in the calculation, akin to rate design, is to decide how to flow the distributed generation developer's share of the zonal pot of dollars to the developer. The parameters developed in this step will be used to derive zonal credits for expected new DG facilities. In theory, the utility should only be required to accept facilities up to some megawatt limit in a DG zone. Today, this limit will rarely, if ever, be binding.
If the DG facility's share of the "pot of dollars" is sufficiently large, then, to avoid gaming, the zonal credit should be unitized on a cents per kilowatt-hour basis over the time period the facilities are expected to provide replacement or deferral benefits. The kilowatt-hours represent the power expected to be generated over the time period by the optimal megawatt capacity for the zone, as determined on the basis of the localized least-cost plan. By flowing through the distributed generation credit on a volumetric basis, the more the DG facility runs, the greater the benefits it receives and the greater the benefits the facility provides to other customers.
A potential drawback to flowing through the benefits on a volumetric basis is that it provides the utility a disincentive to dispatch the DG facilities. The regulatory regime needs to include rules designed to minimize this disincentive.
For a customer installing DG facilities, zonal credits are not the end of the story. More methods are necessary to protect and to provide incentives to both the customer and the utility.
Residual Distribution Service
Rates for residual distribution service are crucial. The crediting mechanism proposed will fail if utilities can take back with one hand what they have given with the other. Most DG customers will not self-supply their entire loads and will occasionally experience forced outages or planned maintenance outages.
Since it is in the utility's interest to erect barriers to competition, utilities have tried to block DG by requiring DG customers to purchase standby or supplemental service at discriminatorily exorbitant rates. Typically, the customer is required to purchase these services under high fixed-cost, low variable-cost pricing, while it would have faced purely or largely variable cost pricing had it not installed DG facilities. These discriminatory practices are improper.
A customer that installs DG is akin to a non-distributed generation customer whose load varies from zero to the customer's non-coincident peak. Accordingly, the DG customer should be no different from any other customer in its ability to select from a menu of service options that vary in terms of firmness and other attributes.
Adjusted Incentive Rates and Performance-Based Rate-Making
A corollary to zonal credits is adjusted incentive rates and performance-based rate making. If a customer adds DG on the customer's side of the meter, under volumetric distribution rates, the utility will lose revenues. As a result, the utility is encouraged to block DG. The issue is how to mitigate this phenomenon.
The solution is properly designed incentive rates. Incentive rates come in two main forms: price caps and revenue caps. A price cap simply places a ceiling on the price a utility can charge. Under a pure application of this mechanism, if a DG facility reduces the utility's sales, the utility loses profits. The solution to this dilemma is simple. To the extent DG facilities reduce the utility's sales, the utility's price cap should be increased.
The second type of incentive rate, revenue caps, requires the utility to adjust prices to offset increases or decreases in revenues stemming from a change in sales volumes. Thus, a utility with a revenue cap is automatically protected against adverse effects on its profits from a DG facility that reduces the utility's sales.
Negawatts and Megawatts
It is widely recognized today that a customer that lowers its consumption at peak provides a benefit to other customers by reducing the peak period price. Indeed, several electricity markets, including PJM and the New York Independent System Operator, have implemented so-called "demand response" programs. A customer that reduces its demand at peak is paid for its reduction or "negawatts" (interruptible load)-just as a generation unit is paid for supplying energy at peak. These programs recognize that there is no difference between the demand reduction and the supply increase, since both make energy available for other customers to consume.
DG is ideally suited to provide either negawatts or megawatts at peak. DG owners can interrupt their utility service and self-supply their entire load (provide negawatts) or increase the output of their facilities above their consumption (provide megawatts). In either case, other consumers benefit by the distributed generation contribution of energy.
In markets where the DG facility may sell its output to a regional transmission organization (RTO) with a demand response program, the DG provider can participate in the program, provided it has adequate metering equipment. In these markets, the local utility need not provide any demand response services to the DG owner. Where there is no RTO demand response program, or where the local utility is a vertically integrated utility that does not afford the DG facility any real opportunity to sell its output off-system, the state regulatory authority should mandate that the utility institute such a program. Included should be provisions that allow DG units and other qualified entities a meaningful opportunity to participate. With the telecommunications capabilities available today, there is no excuse for a utility to decline to provide such services.
Distributed generation likewise is fit to participate in capacity markets. No barriers should hinder DG facilities from participating in these markets. A DG customer willing to commit in advance to be available at or near the system peak provides other customers benefits for which the DG customer should be compensated.
A Fair and Simple Plan
This article points out a "fair and simple plan." The recommendations-the creation of distributed generation zones, utility-side rate incentives, customer-side distributed generation zonal credits, and the elimination of perverse disincentives to distributed generation development-are consistent with this theme. The plan would achieve neutrality among the utility, DG customers, and other ratepayers, and the recommendations can be implemented without making fundamental changes to the current regulatory scheme.
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