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THORNY DETAILS
Louis Harris is a senior regulatory analyst at Edison Electric Institute.
Despite its shining promise, distributed generation confronts a regulatory thicket of technical questions and competitive issues.
 Distributed generation (DG)—whether fuel cells, microturbines, solar, wind, or related technologies—could be the ideal way to introduce demand responsiveness to electricity markets. While policymakers try to outflank unstable and rising prices by correcting flaws in the new electric market structure, you could argue that technological advances may soon offer consumers the ultimate weapon against such instability: their own, self-contained generator.
An increasing number of manufacturers are bringing to market small-scale generators and other resources that can economically provide the electricity requirements for a neighborhood or a single home or business. DG is becoming a viable future option for an end-user's electricity supply, particularly for consumers relatively isolated and expensive to serve. And increasingly, customers could find that DG is out-and-out less expensive as a sole generation source; at the very least, it could offer options to manage the risks of volatile energy costs. Distribution companies, too, can use DG in lieu of direct investment in distribution facilities.
But in any of its uses, DG presents both technical and competitive challenges to the entire electricity industry. On the technical side, DG applications will need reliable fuel supplies, seamless interconnection to the grid, and assurance that the new technology will live up to expectations. On the competitive side, though their dollars per-kilowatt-hour advantage will be difficult for DG to overcome, traditional powerplants and retail energy marketers nevertheless will have a new supply option with which to contend, while distribution utilities will still be obligated to distribute energy to consumers who can self-supply on a moment's notice.
Regulation, never far from the surface in any analysis of energy supply, is beginning to catch up with the technological change DG brings to the market—and as it catches up, it is asking some difficult questions. In several states, particularly California, Texas, New York, and Illinois, market participants are debating rules governing the DG market. These regulations address a wide array of concerns, including ownership and control of DG, interconnection standards, environmental issues, metering and billing, distribution tariffs, back-up and standby rates, net metering, and stranded costs.
In the end, despite the DG promise and its seemingly clear benefits, utilities and their affiliates need favorable answers to several questions if they—and the other stakeholders—are to benefit from emerging DG technologies.
Cutting Costs, Helping the Grid
End users can turn to DG to meet a variety of needs. In recent years, DG has served as a primary or emergency back-up energy source for business applications that place a premium on reliability and power quality. It can also serve load that is difficult to reach with utility distribution. Combined with standby distribution services, DG also offers a new range of hedging options, allowing customers to arbitrage spark spread between DG fuel prices and spot energy prices and enabling greater demand-side response to high supply-side prices. As theorists of option pricing have found, the value of these options increases with market turbulence. In states that allow for retail wheeling, a customer installing DG could choose to sell its entire electric output into the spot market and forgo usual commercial activities.
To equipment manufacturers, DG is a huge sales opportunity. Units can be marketed to developers of residential and business properties, theme parks, malls and other retail shopping outlets, apartment complexes, neighborhood associations, and individual homes. Some suppliers use DG installed on customer premises to offer specialized energy services, such as super-reliable power, heating, and cooling.
There are benefits to electric distribution systems. The distribution company can install a small generator to supplement or defer grid upgrades where space, economics, or other constraints prevent the expansion of substations or the building of new distribution lines. DG can help support line voltage at the end of long distribution circuits. Utilities could also install DG to improve generation quality near isolated loads served by a long transmission line—the small generator might be a more attractive investment option than upgrading the line.
Still, DG could pose a competitive threat to distribution utilities, since it could reduce the demand for local wire services. However, given the value of the options DG conveys to end-users, the distribution facilities needed to exercise those options could be more valuable to the DG installer than ever. Rather than being substitutes, DG and utility distribution could be complements, one enhancing the other.
Whose Plant Is It Anyway?
The ownership of DG facilities is a major question wherever DG policy has been discussed. And it is a question that is posed on both sides of the meter.
For DG on customer premises, some parties, citing market power concerns, contend that utilities should be proscribed from participating in this new market. In California public commission rule-making proceedings on DG last April and May, David Townley argued on behalf of New Energy, Inc., that "participation by the UDC [utility distribution company] creates the potential for market power abuses and cost allocation which does not reflect cost incurrence, all of which is detrimental to the development of a robust, competitive distributed generation market."
Other nonutility market participants would allow utilities to own DG installed on the customers' premises but only through an affiliate, and then only if several conditions were met. These include strict codes of conduct, the UDC filing a pro forma interconnection agreement, the availability of distribution wheeling, a fully transparent UDC planning process for DG, and the imposition of a performance-based rate structure for the UDC.
Utilities have argued that, as with other proscriptions against the incumbent utility participating in new markets, limiting utility ownership of DG would relieve competitors from having to compete against what will likely be the most knowledgeable player in the market. Therefore, efficiency will be diminished if utility involvement were minimized or prohibited. As Southern California Edison (SCE) suggested, "The Commission should not limit a customer's right to choose its supplier of services in a competitive market. Therefore, customers should be permitted to choose their UDC to provide customer DG."
Pacific Gas & Electric (PG&E) also disputes claims that UDC ownership of DG creates market power. Any such market control is mitigated by standardized interconnection requirements, says the utility, and these interconnection agreements are enforced by both California and federal regulatory authorities.
PG&E further contends that utilities should be allowed to own DG anywhere, including facilities installed on the utility's side of the meter—on-grid DG—that function as distribution. These small generators would perform grid functions, such as providing reactance or localized voltage support.
Under current technological and fuel cost assumptions, utilities contend that the number of applications where DG can substitute for distribution will be few. In those few circumstances, SCE argued that utilities, and only utilities, should be allowed to own and operate on-grid DG that functions as distribution. Utilities must own and control these facilities to meet obligations to provide safe and reliable distribution grid infrastructure. While a DG operator could be contractually bound to operate it as dictated by the needs of the grid, SCE contends that contracts, "with their inherent complexity, ambiguity, multiple interpretations, and tendency to resolve disputes, would not allow the utility to fulfill its obligation to provide safe and reliable operation of the distribution system." However, consistent with its open access tariff at the Federal Energy Regulatory Commission, SCE would allow nonaffiliated entities to own and operate on-grid DG that fulfills a merchant function.
The third large shareholder-owned utility with a substantial service area in California expressed a different view. Having just divested fossil generation, San Diego Gas and Electric (SDG&E) does not want to own a powerplant of any kind, even if it functions as distribution grid. As a transmission and distribution utility, SDG&E argues that UDCs will only need to install on-grid DG that is portable and temporary. Such facilities could be used in emergencies to provide temporary grid support, pending more permanent distribution upgrades.
Living in Perfect Harmony
A contentious issue in most regulatory proceedings involving DG is interconnection. DG developers and installers want simple and seamless access to the utility's grid to purchase backup power supplies and to sell excess energy. Given that the economic gains from installing DG will be small, DG advocates suggest that interconnection standards applying to bulk power generators may be too costly and onerous. Since the output from many DG units is likely to be too small to be of consequence to grid operators, these advocates suggest that stringent rules might not be necessary.
With considerable experience interconnecting nonutility generators into the transmission grid, utilities recognize that even small DG poses new challenges. The fact that conditions on different parts of the distribution grid, even within a single utility's network, can be so variable complicates attempts to generalize about DG's grid impacts. As a PG&E witness testified in the California proceedings, the principle factors determining the actual grid impacts from any one DG application include the voltage of the distribution circuit, the location and number of the DG units on a circuit, and the aggregate proportion of DG to any individual circuit's capacity. Complicating the picture further is wide variation in the DG units themselves, including the manner of the connection, the generation technology used, the plant's impact on power quality, the manner in which the plant is operated, the amount of fault current injected onto the grid, and the amount of energy being exported from the facility to the grid. Because of these uncertainties, utilities contend that each DG interconnection must be studied individually—a somewhat costly endeavor.
Utilities further point out that interconnected DG complicates grid safety and reliability, imposing more costs to study the grid impacts of the proposed generator. A DG interconnection might also require the connecting utility to make localized grid upgrades that, but for the DG interconnection, would not be necessary. Utilities favor requiring the installer of DG to pay these costs.
In a joint statement of position by the New York State electric companies for DG proceedings last August in New York, utilities described some of the complexities. Installing synchronous generation in parallel with the distribution system, for example, can cause system overvoltages due to the generator's capability of self-excitation and production of VARs (or volt-amperes reactive). Induction generators used as DG must be brought up to synchronous speed and can cause voltage dip during energization. "Costs could be incurred to correct any unacceptable voltage dip," the statement said.
Several DG technologies incorporate inverter systems that convert direct current (DC) generation to high frequency alternating current (AC) power in synchronization with the external grid. Should power not be flowing on the grid, for whatever reason, the inverter shuts the unit down within a cycle. In their filing, the New York utilities agreed that distributed generators with inverters may offer some advantages, such as lower fault currents and better disconnect capabilities. However, actual fault currents differ among generation sources and inverter technologies, and DC power could still leak onto the AC grid.
Another factor complicating interconnection is uncertainty over the installer's intended use. Many end-users seek DG as back-up during utility outages. Utilities are concerned that DG operation will cause backfeed onto the grid during emergencies, energizing lines thought to be dead and resulting in possible injuries or fatalities to utility workers as they repair downed lines. The same holds true in nonemergencies, when line workers are trying to upgrade facilities.
DG suppliers and supporters agree that interconnection does impose costs that installers should pay. They also agree that interconnection standards are necessary to ensure that DG is operated safely and within the grid's reliability limits. But they contend that utilities exaggerate the impacts and inflate the costs of resolving them—utilities make interconnection costs and operating standards into artificial barriers. Moreover, DG developers argue, the grid impacts from small projects are little different from the impact caused by load management and other customer demand responses to market conditions. Requiring DG installers to incur costs that other consumers do not bear is unfair.
In its filing in the New York proceeding, the Non-Utility Working Group identified several costs it has incurred installing DG projects in the state. Each project included costs of $350 to $500 for utility review application fee, $5,000 to $10,000 for engineering reviews, $500 to $20,000 annually for additional insurance required to meet utility contract requirements, and $5,000 to $10,000 for consulting fees needed to design and field test parallel power protection equipment required by the utility. As a result of these and other expenses, the group contended that a DG project costs $50,000 to $120,000 more than it otherwise would.
Townley testified in California that requiring DG installers to bear the full incremental costs of interconnection "is not reasonable and is not comparable with the treatment of other distribution customers." While conceding that the installation of DG does affect the grid, Townley notes that "so do a myriad of other decisions made every day by other customers without DG." He also argues that, in the case when all the DG output is consumed onsite, many incremental costs currently paid by DG installers alone should be paid by everyone within general distribution rates.
Finally, developers point out that DG also produces grid benefits that are seldom figured into the cost picture. The nonutility filing in New York identified several, including voltage and frequency support, reduction of investment risk, reduction of line losses, extension of distribution plant, and congestion relief.
Everyone agrees that uniform interconnection and operating standards will facilitate the interconnection of DG, as will greater utility experience with interconnection. The Institute of Electrical and Electronics Engineers has put the development of generic standards for DG interconnection on a fast track. In the meantime, some states have developed their own standards. In December 1999, New York issued interconnection standards applied to generators 30 kva and smaller. Also in December 1999, Texas issued interconnection standards applied to DG under 10 megawatts. California has a proceeding underway to develop standards.
Whose Grid Is It Anyway?
One can imagine that several tariff, metering, and billing issues arise regarding DG. Since it can be a substitute for utility distribution, the rates, terms, and conditions in distribution tariffs need to follow closely the costs of providing distribution services. And that can be complicated. An electricity consumer considering supply options will compare the cost of DG, combined with back-up supplies delivered over the utility grid, with the delivered price of electricity available on the market. That evaluation necessarily will include a comparison of utility rates for back-up service and basic distribution. If a utility's standby and regular distribution tariffs do not accurately reflect the costs of providing those services, the option that costs less to the consumer might cost more to society. In this way, faulty distribution or standby rates could encourage inefficient DG installations and discourage efficient ones. In the end, distribution and standby rates will have an impact on generation market efficiency.
Most distribution rates are based on the customer's volumetric, per-kilowatt-hour (kwh) usage, even though most distribution costs are fixed. Volumetric rates include the customer's share of the utility's fixed and common costs, which is derived from the customer's historical load factor. A decrease in load from historical trends lowers the customer's contribution to fixed-cost recovery—so when a customer installs DG and takes power over the grid intermittently, the customer shifts its share of fixed costs to other customers or utility shareholders.
Besides shifting costs, volumetric distribution pricing also distorts energy markets. Since DG can serve as a primary or back-up energy source, it gives customers hedging options previously unavailable—like the arbitrage of spark spread between fuel prices and spot energy prices. Also, in states that allow for retail wheeling, a customer installing DG could sell its entire electric output into the spot market and forgo its usual commercial activities. Finally, an installer can always dismantle the plant and return to the grid for all its energy. If avoidance of paying for the fixed costs of the distribution grid is part of the decision to operate DG (which it implicitly is if fixed costs are recovered in volumetric rates), the efficiency of the decision to install DG will diminish generation market efficiency. Even though the customer experiences lower electric bills, society as a whole pays more for electric generation than it should.
The notion that DG, coupled with distribution, gives options to end-users raises the question of what constitutes use of the grid. Ultimately, these options depend on the utility having distribution capacity available. Like an option traded in financial markets, these options have value—and a major determinant of that value is the volatility in the underlying commodity market. Given the price volatility in most regional electric spot markets, the option value provided by DG could be large. So, the options that grid capacity gives to DG installers that remain connected to the grid means that, in a real sense, installers also are "using" the grid, whether or not energy is flowing across it.
To ensure that DG installers pay for the grid they use, regardless of number of kwhs that cross the meter, utilities in New York and California have proposed standby rates under which installers pay a two-part tariff. In one part, the fixed costs are recovered as a monthly lump sum; in the second part, variable costs are recovered through volumetric kwh charges. While some utilities argue that market efficiency would be enhanced if all distribution customers paid two-part distribution tariffs, many utilities and consumer groups are opposed to such a fundamental change to ratemaking. Some suggest that utilities could preserve volumetric pricing for full-time distribution consumers, while insuring that installers of DG face correct energy market pricing signals by applying two-part pricing only to standby distribution users. Two-part rates applied only to standby distribution will ensure that DG installers do not shift fixed costs to others.
DG developers and consumers generally take a dim view of fixed-cost pricing. Some argue that distribution rates should encourage the development of DG, or, at least, not discourage it. By paying fully allocated, fixed costs in standby rates, note nonutility parties in New York, "the customer contemplating installation of onsite generation would value the cost of such generation as being the capital, O&M, and fuel costs of the distributed generation plus the surrogate billing by [the utility], which essentially doubles the cost of distributed generation."
On behalf of The Utility Reform Network, Bruce Biewald argued, "Such fixed charges discourage load responsiveness to price signals and ignore that over the long term a trend of increasing load results in distribution system constraints and additional distribution system costs." Biewald contends that distribution rates need to leave utilities indifferent to the amount of throughput on their grid, which would result if utility rates were based on revenue caps, instead of price caps.
"For ratemaking and revenue collection purposes, most DG applications are virtually indistinguishable from other technologies and activities that impact a customer's load," Townley suggests. "DG should be treated like any other factor that impacts a customer's load [for ratemaking purposes]. Changes in [utility distribution company] revenues from a single customer should be rolled into the revenue requirements that determine the rates paid by all customers, just as any system benefits that DG provides should be shared by all customers."
Can I Simply Deduct My Output From Your Input?
One issue that has received considerable attention in regulatory proceedings is net metering. In this case, the customer's meter spins at a slower rate whenever the customer's generator operates. If the generator produces more energy than is taken from the grid, the meter would actually spin backward. The question of net metering has emerged in California, which already allows net metering for renewable units 10 kw and under and accounting for no more than half a percent of the distribution utility's load. Other states, such as New Mexico, have similar net metering programs for small renewable generators.
DG advocates support expanding net metering programs to encourage DG. They see it as an easy way to account for DG's contribution to overall energy supply. Net metering also obviates the need to install expensive meters that would be necessary to measure the value of power being produced when it is being produced.
On behalf of the California Solar Energy Industries Association in that state's proceeding, Thomas Starrs testified that net metering simplifies the interconnection process—it enables DG installers to sell energy to the market without having to install separate meters. "In particular," he said, "net metering is a reasonable proxy for the benefits of distributed generation in small-scale renewable applications. The benefits of distributed generation are extremely site-specific and time-specific, and the economic cost of determining the value of those benefits for micro-scale generating facilities . . . would vastly exceed the benefits themselves."
But utilities are concerned that net metering is a back-door imposition of the 1978 Public Utility Regulatory Policies Act's must-purchase obligations, which clearly have no place in a competitive market. Moreover, by tying DG to the retail meter, the user would be getting the retail price for the energy produced. Instead of paying for transmission, distribution, low-income supports, stranded generation costs, and various other costs recovered in distribution rates, the operator would be paid for these services without actually having to provide them. This results in a subsidy equal to the retail mark-up over the spot price of wholesale power at the expense of a utility's other customers and shareholders.
Utilities also point out that the value of energy on spot markets fluctuates widely during the day. Traditional meters do not recognize that an electron generated in the afternoon is worth much more than an electron generated at night. Utilities argue that excess energy produced by DG should be sold in energy or ancillary services markets. In those states that do not allow retail wheeling, if utilities are forced to purchase surplus output, they should have to pay no more than their avoided costs.
Ultimately, the question of metering rests on meter accuracy. If the DG installer were able to track time of use and time of DG operation, and if the meter could track energy flowing in separately from energy flowing out, the net metering question disappears. The United States Department of Energy has called for increased research in metering technology.
Won't DG Automatically Be Better for the Environment?
DG is often mentioned in the same breath as renewables—and therefore is considered environmentally benign—but in fact the environmental impact of DG in general is largely unknown. Right now, most existing DG units are emergency diesel generators that are far dirtier to operate than almost any central station powerplant. While renewable fuels may have minimal environmental impact, a proliferation of fossil-fueled DG could cause localized air-quality degradation.
A recent analysis by James Lentz, of the University of California/Riverside Center for Environmental Research and Technology, found that all natural gas-fired DG technologies had a worse environmental impact than the most efficient combined-cycle gas turbine baseload powerplants. But in a recent study sponsored by the National Association of Regulatory Utility Commissioners, David Moscovitz contends that gas-fired microturbines could provide opportunities to reduce emissions by improving the efficiency with which energy is consumed, through improved heat rates and combined heat and power applications.
In any event, one utility concern is the fact that many smaller fossil-fueled DG units are not subject to the same emission and environmental standards and oversight that apply to larger, central-station utility facilities. These reduced emission and environmental standards give DG an unnatural competitive advantage compared to conventional powerplants, which must adhere to more rigorous environmental standards. California and Texas, by the same token, have extended their environmental standards to DG units.
Real Choices
So, DG provides a hitherto unavailable tool to help remedy energy market turbulence: Customers have an option not to purchase energy on the market but to generate it for themselves. One only has to look at the recent electricity spikes and supply shortages in California to appreciate how both utilities and their customers could benefit from DG in the future. Meanwhile, DG still has a regulatory hill to climb—the issues about environmental standards, ownership and control, interconnection standards, metering and billing, distribution tariffs, back-up and stand-by rates, and net metering are only beginning to be resolved, and then only in a few states.
Still, as policymakers and market participants seek solutions to design flaws in newly restructured markets, they would do well to focus on a powerful player—the electricity consumer—and the choices he or she faces. If past is prelude, innovators will continue to bring to market new technology that will make his or her options more meaningful and valuable—and that makes it more important than ever to answer these questions sooner, rather than later.
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