The T&D grid, once deemed a bottleneck, will now face pressure from both ends. Is it still the same old monopoly?

Some 30-odd years ago physicist and philosopher Thomas S. Kuhn coined the phrase "paradigm shift" to describe a radical change in a mental framework for interpreting facts. His key work, "The Structure of Scientific Revolutions," published in 1962, focused on the role of paradigms in scientific thought - such as the Copernican sun-centered solar system or Planck's work in quantum mechanics. In the energy industry, however, the notion of shifting paradigms gained popularity only during the 1980s. Analysts began to use the phrase to communicate the profound changes in regulation and industry organization brought about by fostering open access to the natural gas transmission and distribution system, a process that began in 1985.

Nevertheless, while the idea of mandating open access to interstate transmission networks often is referred to as a "paradigm shift," it is easy to overlook the extent to which this seemingly new approach shares certain fundamental assumptions with the preexisting regulatory paradigm. Both assume there are rising economies of scale in transmission and distribution lines, and that supply - whether gas production or central station generation - is located a fair distance from the point of sale.

These two assumptions, in turn, presuppose that transportation facilities tend to be bottleneck monopolies (or oligopolies, at the least). Control of the bottleneck is thought to yield considerable revenues in excess of cost-revenues that regulation seeks to control. The traditional regulatory paradigm restricted entry by defining "service territories," and then set prices based on the monopoly seller's cost. The new, open-access model maintains much of the traditional regulatory approach for the transmission component of the industry while opening transmission access for supply of the transported commodity.

In natural gas, open access worked to lower city-gate gas prices and expand markets. By the 1990s, the success of the open-access model for gas encouraged regulators to adapt it to the electric power industry, a process still underway.

But a funny thing happened on the way to the new paradigm for the power industry. While everyone focused on rearranging the ownership structure for generating assets and new pricing and transmission institutions to address the bottleneck T&D lines, the basis for the paradigm already was shifting. Changes in consumer demand for power quality were combining with new generation and power management technology to begin to upset the underlying economic geography of the industry.

Imagine for a moment: How would the gas industry model have fared if, back in 1989 or 1990, some new technology had come along, allowing industrial and commercial customers to drill gas wells on their property and feed gas back into the lines on the coldest days of the year?

On the electric side, that scenario now threatens, putting the "what if" question squarely before the industry in the context of regional transmission organizations. As a result, several questions arise about T&D assets:

* Will the assets be bottlenecks or rather bottlenecked by price pressure from power supply at both ends of the line?

* Will they serve primarily as carriers of bulk goods or as integrators of retail information?

* Does the value of the wires lie in their ability to transmit power or to serve as an interactive customer interface? And if the latter, what is the comparative value of this manner of customer interaction in competition with other forms of aggregating diverse consumer demands?

In short, the industry may be moving toward an electronic transmission and distribution model, or ET&D. Such an industry structure is quite different from the "common carrier" model on which the open-access rules are predicated.

Power Quality:

Pressure from Below

On the demand side, the development of electronic commerce in all its forms is causing the need for high-quality power to skyrocket. This e-commerce revolution means that a fast food restaurant with gas-fired grills can't sell so much as a salad if a power outage puts the cash register/integrated-inventory-management system out of commission. A single instant's outage in an office building can set off wailing and gnashing of teeth as spreadsheets and pleadings vanish without warning.

Companies relying on computer-based systems for dealings with suppliers and customers are similarly at risk. As a result, ordinary commercial customers now are demanding power quality at standards that used to be reserved for precision manufacturers. This trend is expected to continue with society's increasing dependence on electronic information appliances, and will make itself felt in the marketplace as a premium consumers will pay to ensure high-quality, reliable service.

Microturbines:

Pressure from Above

At the same time, on the supply side, equipment manufacturers have significantly improved the performance and economics of small-scale, dispersed power generation and management systems. For example, microturbines now are available that promise sufficiently low capital and operations and maintenance costs to make self-generation feasible for many more customers with much smaller loads than in the past.

Because of their relatively small size, the new units typically are located on the customer's premises. For example, 75-kilowatt demonstration units are now being tested at fast food restaurants, and, if successful, may be adopted in coming years by vast numbers of similarly sized commercial customers. In addition, fuel cells are being commercialized, with additional power quality, environmental and other advantages that may offset potentially higher costs. Solar and other renewable technologies also will be suitable for location at particular customer sites.

The improvements in these smaller-scale technologies have come quite recently - virtually overnight, when compared to the seemingly glacial pace of regulatory proceedings. Figure 1 shows improvements in gas turbine efficiency during the last 20 years. As shown, while improvements in the efficiencies of larger, single-cycle gas turbines have been fairly continual over time, striking changes have come recently in the smaller units.

These improvements in operating efficiencies translate into increasingly more attractive economics, as illustrated in figure 2. Technological "miniaturization" likely will continue to keep driving down the unit costs of small generation equipment to keep pace with falling costs of larger machines. While very small-scale generation remains more expensive than power at the busbar from new, large merchant plants, distributed power frequently offers additional, site-specific benefits, the value of which may not be reflected in power price calculations alone. These "geographic" benefits include (a) power quality for sensitive loads (a particular advantage of fuel cells); (b) savings from cogeneration, now called CHP (combined heat and power); (c) opportunities to dispatch on-site generation and load management to reflect local power and gas prices and local needs; and (d) avoided costs to the T&D system, reflected in avoided T&D charges. With these benefits, distributed power increasingly competes economically with the market prices of power supplied from the grid.

The small size of these new units implies a different geographic pattern of generation. This dispersed pattern, in turn, implies different roles in the power grid. These different roles require a different interface with the existing T&D line, both operationally and commercially. Together, these changes require a new operational, commercial and regulatory conception of the power industry. In sum, the new, dispersed generation technologies increasingly look like "paradigm busters" that will force changes in the "newly traditional" open-access paradigm just as surely as open-access overwhelmed its predecessor.

Interconnection: Now a Two-Way Flow

The new distributed resources have another characteristic that makes them quite different from existing central station plants: In most instances, electric power will flow to as well as from the customer. Depending on the relative economics of available supplies (and the rate consequences of different operating decisions), the distributed generators may be used either as base-load units, with third-party, grid-based sources supplying the "swing" power, or as peak-shaving units, with the grid supplying the base, off-peak load.

In this interactive world, no generation plant need be an island. This dynamic interconnection of on-site generators with the grid poses real and significant issues as to synchronization with the grid, routing and accounting for power flows, assurance of frequency harmonization and the like. But significant benefits are made possible as well, including the coordinated use of dispersed generation to help compensate for supply outages from central station facilities, or to overcome transmission limitations to serve constrained load "pockets" - steps that could have helped ease the kind of blackouts experienced this past summer. Much as changes in the pattern of usage of gas pipeline transmission lines and storage facilities in the 1980s required new operational terms and conditions, as well as new business processes for addressing them, the interconnection of distributed power resources will require significant changes. Legitimate concerns of the T&D companies must be addressed, as must the need to ensure safety and reliability. At the same time, regulators must be alert to the potential for artificial operational restrictions on distributed power development.

Squeezed Margins:

Competitors Pay No

Wheeling Charge

Under the old, "cost-plus" paradigm, the assumption was that the retail price of electricity service would equal the sum of the cost of producing, transmitting and distributing the power to the customer. The new, open-access paradigm shares this basic assumption, while assuming that the electricity production component of the equation would be set by a newly competitive wholesale market.

The economics of distributed generation, however, appear to promise a long-term, unpleasant margin squeeze quite at odds with the traditional equation. The math is simple. Today, the average cost of production from the generation plant is on the order of 4 cents per kilowatt-hour. The average cost of T&D is around 3 cents per kilowatt-hour. In the old, cost-plus world, the retail price was determined by the sum of production, transmission and distribution, yielding average retail prices of around 7 cents per kilowatt-hour.

However, the cost of power from distributed resources is expected to approach, say, 6 cents per kilowatt-hour in many applications and locations. Sometimes this 6 cents may be the cost remaining after charging some costs to products other than commodity power (e.g., power quality or thermal energy). When costs such as these are achieved, the fundamental equation for the next decade is that production, transmission and distribution cannot materially exceed the otherwise available retail price. To put the matter a bit simplistically, 4 cents plus 3 cents must find some way to equal less than 6 cents.

This equation identifies the battle lines. Owners of central station plants will redouble their efforts to lower their own costs and begin to participate in the regulatory process to constrain regulated T&D costs. Owners of the T&D facilities similarly will seek to reduce costs. At the same time, they will assert, quite rightly, that there are costs associated with interconnecting to the existing grid, providing backup or standby service, etc. The economic attractiveness of the distributed option will be affected significantly by how these costs (together with offsetting T&D benefits) are recognized in new distribution rates.

It won't take vast numbers of distributed units to have a vast impact. What matters most is whether the marginal cost of distributed power (net of non-commodity benefits and charges) falls below the marginal cost of power delivered from the grid. As this occurs - as it is seen to occur - industry participants will respond far more quickly than regulators might imagine to adjust prices, costs and services. A few hundred megawatts will have an impact on the market far in excess of their actual generation capacity.

Regulatory Questions: Uncharted Territory

Distributed generation challenges the conventional regulatory paradigm in part because of the difficulty in classifying it either as a competitive or regulated monopoly function. In fact, it may be both. Specifically, the new technology forces to the fore threshold questions regarding what entities will play which roles in the new industry. These questions concern the management of facilities and assets.

Who Owns the Plant? The battle here pits the regulated local utility against a competitive generator. Presumably, the construction of new power facilities on the customer's property would be a competitive function. At the same time, however, other applications of distributed power will be located at distribution substations (or elsewhere on the T&D system) and presumably would be owned by the utility.

Perhaps the real question is whether ownership of the new assets at either utility or customer sites will be determined by regulators to be an acceptable function for a regulated monopoly, especially where utilities have divested central station generation. To what extent will the regulated entity be allowed to compete with unregulated developers of distributed power resources? If the utility itself is barred, what code of conduct should govern participation in the new business by an unregulated affiliate of the utility?

Who Controls Dispatch? Here again, analysis turns in significant part on whether distributed power is viewed as a competitive function only, or one that also is part of the regulated utility function.

Self-generators and unregulated distributed power competitors will be able to make their own decisions about when to operate the new asset, based on power and gas market conditions (and potentially based on real-time price or other signals about available capacity and pricing on the distribution system). These decisions could apply to a single site or across a group of sites operated by a single distributed power company.

Regulated utilities presumably will be able to offer the service of dispatching generators owned by others, taking into account distribution capacity needs as well as generation market prices. The tough question here may be whether any new institutional entity will arise to monitor, facilitate, coordinate or automate the dispatch of potentially thousands of small generators and load management systems. Such new entities might include an "independent distribution organization" (IDO), a local power exchange, or perhaps a local dispatching service of a regional independent system operator or utility. The new IDO conceivably could be a private, for-profit venture, in which case it might be termed a "virtual utility," with responsibility for coordinating operations with the utility grid as well as optimizing the economic value of the distributed power asset. Such an entity largely would be an information integration and management business.

The scope of the changes outlined above likely will require considerable revisions to the regulation of both rates (see sidebar, "No Gen is an Island") and operational terms and conditions. Considerable time and effort will be required to develop and implement these new rules and rates. The principle of "comparability," which has informed so much of the open-access paradigm, will be inadequate to fully guide this development because so many of the changes will raise new issues where there simply isn't any "comparable" utility rate or practice to apply.

The power industry today must come to grips with underlying changes that are truly profound. The industry must develop a business and regulatory model that recognizes these fundamentally altered patterns of production, consumption and distribution. It is a task that lies considerably beyond the scope of the present essay, whose goal is to initiate, not culminate, this debate.

Francis H. Cummings is a principal at XENERGY Inc., where he directs the company's consulting practice in distributed power. He was director of policy at the Massachusetts Division of Energy Resources from 1994 to 1998, where he developed and negotiated the state's approach to voluntary divestiture of generating plants.

Philip M. Marston, counsel to XENERGY Inc., is an attorney and consultant who has written and spoken widely on regulatory issues affecting the regulated gas and power industries over the last 20 years. Marston has been called one of the architects of the open-access revolution in natural gas as a result of his work as assistant to the chair on FERC Order 436 in the mid-1980s.

No Gen Is An Island

New rate-making principles for the distributed power market.

If customers install on-site generation, regulators must rethink the basic principles that govern grid services and backup power. Here is a list of principles to consider.

1. Assure the collection and e-distribution of necessary operational data. New information on the impact of dispersed generation on individual segments of the distribution system (e.g., feeders and substations) will be needed to rethink both class and customer-specific prices. Accordingly, information regarding conditions on these segments will need to be comprehensively collected and "e-distributed" to the market on a real-time basis.

2. Send accurate price signals to the "Distributed Power Market." Distribution rates and performance-based rate-making mechanisms should give customers incentives to invest in distributed generation where it is economically efficient compared to utility T&D investments (e.g., through real-time locational prices).

3. Balance equity and efficiency concerns. Many public policies are at issue in the selection among generating options. The rules governing distributed generation should take into account the full range of public policy goals, which may include such diverse objectives as encouraging energy efficiency and diversity, minimizing adverse effects on global environment and maintaining equity among all classes of ratepayers.

4. Avoid unneeded "islanding" of facilities. In designing or approving rates to distributed generators, care should be taken to avoid creating unintended incentives for users to isolate themselves from the grid. If standby charges are too high, users may respond by installing multiple, smaller generating units - providing their own redundancy and/or diversity - and avoiding the standby charge entirely. From a public policy perspective, that could lead to an economically inefficient level of investment in both T&D and generation assets.

5. Define new distribution services. Customers should be able to select distribution service with different levels of reliability (e.g., firm or non-firm), and a level of standby service that corresponds to the amount of on-site capacity that they wish to back up.

6. Recognize upstream T&D benefits. Standby rates should reflect physical and economic benefits obtained by the T&D system, or T&D benefits should be returned to self-generators through a credit mechanism.

7. Reflect realistic probabilities of outages. Rates should reflect the diversity of generating resources on the distribution system (e.g., many small generators impose less risk than one generator of the same total capacity), and the high availability of new generating equipment.

8. Reflect frequency of actual use. Standby rates should be based on actual usage of distribution capacity, to provide incentives to minimize use during times of peak load on the affected portion of the T&D system.

9. "No harm, no foul." Standby rates should charge capacity costs only for on-site generation outages that occur at the distribution system's peak, not for demands when excess capacity is available.

10. Load Reduction. Standby rates should credit customers for arranging load reduction within the affected portions of the T&D system that offset generator outages.

11. Interconnection Policies. Requirements for interconnecting customer-sited generators to the distribution system should be designed to assure safety and reliability, without interfering with the distributed energy market.

- F.H.C. and P.M.M.

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