Fortnightly
Distributed Generation: Last Big Battle for State Regulators?
October 15, 1999
By Richard Stavros
California again is the proving ground. Analysts see DG as the biggest issue since the PUC first mapped its "vision" for retail competition.
The distributed generation (DG) debate among utilities, environmentalists, power marketers, manufacturers and consumer advocates, set to move into second gear late this year before the California Public Utilities Commission, promises to "be a bloody, back-biting, nail-scratching fight."
That is the belief of Michael Shames, director of advocacy group UCAN, the Utility Consumers Action Network, who participated in early June hearings spurred by a CPUC Order Instituting a Rulemaking (OIR) on DG. (See RM98-12-015, Cal.P.U.C.; also, www.cpuc.ca.gov.)
UCAN's Shames observes that the DG issue pits industry groups against each other because it throws everything done by utilities as part of electricity restructuring into question, both in California and nationally.
"The utilities have recognized that the greatest asset they own is the grid," he says. "They view those wires as the future in which they can offer commodities. The utility distribution companies (UDCs) must view distributed generation as a competitive threat. Their own business, their own assets, the distribution lines are at risk by the development of a distributed generation market."
All of this makes for a spicy stew. On one hand, distributed generation represents a budding and exciting technology. It may demand new policies and standards from regulators on such matters as utility interconnection and net metering. At the same time, however, DG might render obsolete a good deal of what regulators have done so far concerning direct access, functional unbundling and forced divestiture of generating assets.
Fighting for Turf: A Feeding Frenzy
The California PUC recognizes DG's threat to utilities. According to CPUC press materials, "The portability and in-house capability of such facilities could enhance or replace some key functions of the major utility distribution companies - Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric - and thus have significant implications for their transmission and distribution systems."
Nonetheless, the CPUC hopes to explore the potential for competition in distribution services, including distributed generation, and roles and responsibilities of the big electric distributors. Distributed generation (also referred to as distributed energy resources) generally refers to small, modular electric generation and/or storage devices that are installed close to the customer's premises. Microturbines, fuel cells, photovoltaics, wind turbines and flywheels are examples of DG.
"This could well be a shark-feeding frenzy," says Shames. "The utilities clearly want to enter the DG market, but the DG market is actually split on the issue.
"[On one side of the argument], some [microturbine manufacturers] want utility intervention because they believe that utilities will facilitate or accelerate the deployment of their technology. It is big bucks. [Utilities] are the companies with deep pockets who have a vested interest in spending the money," he says.
On the flip side, according to Shames, other DG companies, manufacturers and retailers want nothing more than to avoid utilities entering the market because of market power issues.
For example, when a utility deploys DG - whether on the customer's side of the meter or on someone's roof or house - it benefits from a distribution perspective, he says. Even if utilities install DG at a loss or at cost, the bolstering of circuits on the distribution line allows it to avoid upgrading that line or putting in transformers or substations, Shames says. These benefits give utilities a distinct competitive advantage.
"There is no way that any DG company could compete with a utility [because of utilities' cost benefits] he says.
But Michael D. Montoya, attorney for Southern California Edison, argues that control of grid operations must remain with the utility. He notes, "As the responsible provider of distribution service, the utility must have control over on-grid DG applications and be responsible for planning, designing, constructing, owning, operating and maintaining such on-grid DG."
SCE says it is imperative that utilities determine the location of on-grid DG applications in order to ensure reliability, integrity and safety of the system. But not all utilities agree with this view.
San Diego Gas & Electric, in comment filings, stated, "Even with over 70 cogeneration systems installed on its system, SDG&E has not, with a few isolated exceptions, experienced significant problems with existing customer generators that ¼ adversely [impacted] the overall T&D system with regard to integrity, safety and reliability."
SCE, however, asserts that DG is a wires asset. The utility agrees with the Coalition of California Utility Employees that non-utilities should develop and own DG owned and operated for the benefit of the grid.
In filed comments, the CCUE notes, "The question implies that there is something intrinsically different between DG and any other component of the distribution system. Utility Distribution Companies are not required to let others own or install transformers, and the same should be true for DG."
Yet Jay Morse, project coordinator at the CPUC's Office of Ratepayer Advocates, says that the implementation by commercial and industrial customers of "islanded" self-generation [generation running apart from the grid] demonstrates that the UDCs no longer have a monopoly on distribution service. Since distribution is not a monopoly for customers with DG, it cannot be a "natural monopoly."
"To put it simply, permitting UDCs to own, lease or control DG as distribution investment or expense violates electric restructuring. Just as reducing transmission costs does not justify booking central station generation as a transmission asset, so does reducing distribution expenses not justify booking distributed generation as distribution," he says.
Permitting UDCs to own or lease DG as wire assets is different only by degree from permitting them to exclude others from doing so, Morse says. "Neither AB1890 [California's principal electric deregulation law], nor the CPUC's Preferred Policy Decision [D.95-12-063, Dec. 20, 1995, 166 PUR4th 1] treat or define generation in any way that could be interpreted as excluding DG. Therefore, DG, like central station generation, must be functionally separated from transmission and distribution and excluded from transmission or distribution rates."
SCE's Montoya disagrees. "While SCE acknowledges that there are some conceptual similarities between the relationship of central station generation and transmission on the one hand, and distributed generation and distribution on the other, these similarities are not 'precise,' as alleged by ORA," he says.
Furthermore, Montoya says, utilities are pursuing on-grid DG to provide a "cost-effective substitute" for investments in traditional distribution facilities. "The primary purpose is not to supply generation in competition with central station generating plants. Moreover, the supplies of energy attributable to on-grid DG will simply be too small to give the DG owner the ability to influence prices in whole sale energy," he says.
"However, even for the sake of argument that ORA is largely correct, it simply does not follow, as ORA asserts, that utilities should be precluded from owning on-grid DG. Neither the Commission nor the Legislature has ever concluded that utilities should be precluded from owning any generation in order to solve some perceived horizontal or vertical market power problem. Indeed, the Legislature in AB1890 specifically provides that utilities can continue to own generation if it is in 'the public interest and would not confer undue competitive advantage.'"
In reply comments, generator manufacturer Caterpillar handles the issue of whether UDCs should own DG diplomatically. "During the formal phase of the OIR, all possible roles should be carefully considered in the context of market power and the ability to contribute to a robust competitive market. In this regard, we would also suggest [that] focusing on ownership of distributed resources would lead to a briar patch of debate. Ownership is subordinate to the determination of a leadership role for the distribution company. ¼ It would be ill-advised to limit the range of choices at this stage of the OIR."
Local Distribution:
Does Competition Make Sense?
Distribution competition means different things to different parties, argues ORA's Morse.
Morse says Southern California Edison considers distribution competition to include "governmental acquisition and ownership of regulated public utility distribution systems."
Conversely, Morse notes that PG&E seems to use the term to mean "wires competition," which is competition between duplicative wires and other facilities. In contrast to Edison's definition, PG&E seems to exclude governmental monopoly suppliers, such as irrigation districts (IDs), from the category of distribution competition. For example, PG&E states, "that West Side cities choose Turlock Irrigation District as a new monopoly distribution provider instead of, not in competition with, PG&E."
Clarity in this proceeding requires that duplicative facilities competition be understood as only one of many forms of consumer choice in distribution, Morse says.
Irrigation districts represent at least two distinct forms of distribution competition, he notes. Furthermore, municipal utilities implicitly represent competition among different forms of monopoly, he says.
"The competition takes place at the government level; government, rather than individual customers, decides on the distribution providers," Morse adds. "IDs could be a useful check on UDC rates on their regulation. The CPUC needs more information on the factors underlying the ID's cost advantages before determining what measures incumbents should be allowed to take at ratepayer expense to compete with IDs."
ORA believes reforms are needed to levelize market entry of DGs, munis and IDs with UDCs, he says. However, adds Morse, the PUC cannot require IDs and munis to unbundle distribution services, separate DG from distribution services, or take other measures to mitigate vertical market power.
Many stakeholders filed comments attempting to separate DG and distribution competition (DC) in the debate because they say DG can be solved more quickly than the DC argument.
Reliability: A Need for
Standards?
SCE says that too many different types of DG would degrade the reliability of the system. Reliability of the distribution system ultimately depends upon SCE's controlling every meaningful aspect of design and construction, the utility says in comment filings.
But SDG&E asserts that degradation of safety can be prevented by simple adherence to common design, construction, operation and service standards.
Furthermore, Ake Almgren, president and chief executive officer at Capstone Turbine Corp., says interconnection requirements need to be standardized across the state and streamlined. In addition, he says, these requirements need to reflect both the interconnection technology and the size of the unit being interconnected to the grid.
"Interconnection of small distributed generators (less than 300 kilowatts) can be made in a safe and simple manner given modern technologies such as a solid-state digital power controllers," Almgren states in comment filings. "This technology [used by] Capstone enables the interconnection to the grid to be controlled by a microprocessor, which can be programmed to meet a full range of protective requirements. Moreover, in grid-connect mode, this technology is configured to use the grid as its voltage source. Islanding cannot occur because the generator will not operate without a voltage source supplied from the grid."
Almgren says interconnection of DG to the grid should be simple and the interconnections should be tested against a specified standard, rather than going through time-consuming case studies.
However, critics of forced standardization fear a hodge-podge of rules driven not by technical requirements, but resulting from outdated regulatory policies.
According to one analyst, "Most of the requirements were developed in response to section 210 of the Public Utility Regulatory Policies Act of 1978 that required the UDCs to interconnect with [qualifying facilities], namely, cogenerators and small power producers meeting the Federal Energy Regulatory Commission's ownership, operating and efficiency standards."
He adds, "These standards were developed in the early to mid-1980s, and they still rely on expensive electromechanical devices that are no longer state-of-the-art. Tremendous advances in power electronics and computer systems can allow system designs that are an order of magnitude less costly than the specified equipment."
Yet Kurt E. Yeager, president and chief executive officer of the Electric Power Research Institute, asserts that local generation is "transforming today's radial, electromechanically controlled, open access, smart network."
Stranded Assets: Is the Grid Next?
Distributed generation could render obsolete billions of dollars worth of utility distribution networks in California, say analysts, but not without a fight from utilities. In fact, UCAN's Shames says that the stranded-cost wars over generation will pale in comparison to what we can expect if DG renders distribution networks obsolete.
Is the CPUC responsible for the viability of utilities?
"You have just raised the ugly head of Stranded Cost II. It is not a pretty picture to envision a war over the distribution system," replies Shames.
ORA's Morse, however, does not believe that distribution networks will be undermined by DG. Rather, he says, both technologies will work in concert.
The California Manufacturers Association says that since DG helps UDCs avoid additional investments in distribution facilities, there should be no reason to "protect" them from any claimed revenues or stranded investments. Furthermore, PG&E and Edison argue that DG may substitute for more-expensive distribution investment.
In addition, Morse argues against acceleration of stranded cost or a request by PG&E to implement a wires charge for exiting customers in order to recover its lost margin.
UCAN's Shames breaks down the utility costs as they relate to generation and distribution. "In California, the average residential bill is about 10 cents a kilowatt-hour. The cost of generation costs 2 cents and between 4 and 5 cents is distribution; a penny for transmission and about 2 pennies for public goods and surcharges," he says. "[You're] looking at twice [the cost], if not more, than your kilowatt-hour being attributed to distribution functions."
Comments from the attorney representing Enron, Michael B. Day of Goodin, MacBride, Squeri, Ritchie & Day LLP, support the argument against stranded cost.
"Recent experience shows that, in contrast to the generation sector of the industry, the distribution sector is less susceptible to the risk of stranded costs. For example, in each of two recently approved sales of utility distribution facilities, the sales price exceeded the net book value, i.e., there were no stranded costs. Instead, there were benefits. Indeed, if structured properly, distribution competition could well result in greater use of the existing utility distribution system, with a corresponding increase in utility revenues," says Day.
"[Furthermore], certain tariffs represent some of the thickest regulatory underbrush" that the CPUC needs to clear on behalf of consumers, he says. "Specifically, in order to encourage competition in distribution services, the Commission must reform or eliminate certain aspects of the electric standby tariffs, the residual load service tariffs are applied in a way that effectively discourages customers from choosing service from any entity other than the utility."
Day adds, "If these tariffs and charges are salvageable, they need to be reformed to reflect only the utilities' cost of providing required service. The tariffs should not be used as a means to discourage innovation, choice and competition."
Capstone's Almgren also takes a strong stance against stranded cost. "Capstone believes that distributed generators should not be burdened with the cost of stranded assets. Distributed generators were not party to the decision that resulted in these stranded assets and should not be required to fund them," he says.
"Stranded asset charges, including the [competition transition charge], are a major obstacle to the development of a competitive electricity market in California. These charges add significantly to the cost of alternative power and, in many cases, undermine the benefits of the alternative including DG," Almgren says.
"Commercial business takes risk with its investments and wears the consequences, for good or for bad. In all instances, it is not clear what the economic value of the so-called stranded assets will be and so it is very difficult to compute the level of the charge with real certainty."
The Next Generation:
A Closed Club for Gas Turbines?
Eileen Smith, founder and chief executive officer of Solar Development Cooperative, says the industry has not given photovoltaics and renewables a fair shake as alternatives to gas-fired microturbines as DG.
"Renewable energy resources are viable alternatives to gas turbines, meeting our sustainable energy goals with competitively affordable deployment," she says.
Smith adds, "CPUC's ORA's Opening Comments forecast the price of gas turbines (with gas fuel that is highly unpredictable) at a level of 100,000 units per year. Building integrated photovoltaics (BI-PV) and fuel cells have been adequately demonstrated in the past 20 years and have reduced in price enough to justify their mainstream deployment as a priority focus in [CPUC proceedings]."
Furthermore, Smith attacks ORA's Morse for what she sees as prejudicial statements against PV.
According to ORA comments, "Photovoltaic (PV) sales are growing at a rate of 30 percent per year, but PV systems cost 10 times as much as gas turbines to purchase and install, and three times as much to own and operate."
ORA does not mention any consideration of externality costs and fossil fuel deployment, Smith responds. The primary cost of gas turbines, she argues, is the gas fuel one must purchase to use the turbine.
Smith breaks down the costs of PV.
"[For example], consider a 7-kW peak project in Southern California. This project will produce an average of 42 kWh per day. That is 12,600 kWh a year, or around 34 kWh 365 days a year." The going ratepayer price for electricity is 12 cents per kilowatt-hour, which averages to around $1,500 a year, she says. By contrast, BI-PV averages $1,250 to $1,400 per year when all costs are accounted for, Smith says.
"It does not at any time cost 10 times the amount of turbines. The BI-PV has predicted a 30- to 50-year life with minor maintenance and repairs. With this figured in, that means a ratepayer is only paying an average of $600 per year ¼ with a savings of nearly $1,000 a year," she says.
Furthermore, Smith believes the adoption of a 50-year warranty for solar electric rooftops, now warranted for five years, and the ability to wrap BI-PV costs into a 30-year mortgage would greatly increase sales and production levels.
Industry analysts estimate that solar power is an approximately $2.0 billion business, growing in excess of 20 percent per year. While an estimated 76 percent of solar cell capacity installed in 1997 was in remote applications, unconnected to the power grid, it is expected that grid-connected applications will grow rapidly. Increasingly, solar power is finding on-grid applications for peaking power and to meet customer preferences for "green power," according to Hugh Holman, senior equity analyst at BancBoston's investment bank, Robertson Stephens.
"We believe the restructuring of the electric utility industry in the U.S. and Europe will prove to be a powerful catalyst in creating new opportunities for grid-connected solar power," he says.
Of course, there are institutional barriers to on-site generation, which Holman says will ease over time. "These barriers include stringent or prohibitive interconnect requirements, fixed transmission and distribution capacity fees that must be paid regardless of how much electricity is drawn from the grid, and transition charges that can only be avoided by decoupling entirely from the grid (thus losing the grid for backup or baseload power)."
ORA's Morse, who attended a DG conference in mid-September, says he found that much of the software for integrating DG with the grid, while allowing anyone who wants to interconnect and be dispatched for reliability, is improving.
"There is not going to be a problem for hundreds of thousands of small power units to get connected to the grid. It will be possible to orchestrate them for reliability purposes," he says.
Of course, the issue of whether UDCs should be permitted to unbundle services in distribution in a way that utilities were not permitted to do in transmission still remains a hot debate, Morse says.
The most contentious issue in the next few months will be the role of the UDC in DG, he says. In addition, interconnection will prove a top issue for the CPUC, as well as tariff issues such as standby charges, customer charges, exits fees and rate discounting, predicts Morse.
Richard Stavros is senior editor of Public Utilities Fortnightly.
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Interstate Transmission: A Second Front
DG has a bone to pick with the FERC as well.
Even as the California PUC wrestles over who should control the local distribution grid, the Distributed Power Coalition of America (DPCA) has mapped out a direct interest in the formation of interstate regional transmission organizations (RTOs), because owners of distributed power units will become customers of the regional entities. The DPCA is a coalition of companies and organizations whose mission is to advocate the adoption of distributed energy resources.
Sarah McKinley, executive director at DPCA, says that distributed generation, or DG, known to offer residential and commercial customers generation options, also could be employed on the transmission level. She lists several potential benefits.
* Enhancement of grid reliability by strategic placement of DG facilities. DG can enhance grid reliability when transmission service is disrupted through mechanical failure, crippling storms or other natural disasters.
* Commercial use of distributed energy, primarily for peaking load. That will allow customers to take advantage of the "spark spread" between peak electricity prices and the cost of producing their own energy, primarily fueled by natural gas. Pricing software, combined with control technology, would allow units to be turned on at economically opportune moments to capture these efficiencies.
* Combined heat and power applications. Many commercial and industrial users can use waste heat generated in their operations to produce electricity.
* Industrial or large commercial applications. On-site energy production would displace existing load.
* The use of DG to provide ancillary services. An emerging market for ancillary services most likely will include participation by energy service companies or third parties, many of which plan to use DG units to serve this market need.
Furthermore, McKinley dispels the misconception that DG is appropriate only for small users on the distribution system. Indeed, the membership of DPCA includes major corporations that plan to deploy on-site generation in sizes much greater than 50 megawatts.
But before DG can be deployed on the transmission network, McKinley says, nationwide differences must be settled in definitions between transmission voltage and distribution voltage across the United States.
Furthermore, "the sizes of the lines will also make tremendous difference in how units will be defined," she says. "In some areas of the country a generator at one point will be connected to the local utility system, and a similar unit elsewhere may be connected to the transmission system."
For example, says Evelyn Elsesser, representing the Energy Producers and Users Coalition and the Cogeneration Association of California, "when the Independent System Operator (ISO) took control in California, the utilities were required submit a split for transmission and distribution. If you recall, Pacific Gas & Electric's split was 66 kilovolts and Southern California Edison's is at 220 to 230 kV.
"If you take a cogenerator and define distributed generation injected at the distribution system, you may find a cogenerator in one territory that falls into your definition and a cogenerator in another territory who would not because they happen to fall on the transmission side of the interconnection," she says.
Elsesser says this will lead to a jurisdictional problem in which, "some facilities may be treated by FERC under the interconnection rules and some may be treated by [the California] commission," even though the facilities may be the same size.
"The ambiguities that occur between the distribution and transmission systems point to the necessity for uniform, national interconnection standards to ensure the creation of a seamless national electric grid," she says.
"The DPCA recognizes that the [FERC] does not have authority to establish interconnection policies at the state level," says Elsesser. "However, the coalition believes that uniform interconnection policies promulgated through the rulemaking would help to overcome barriers to entry for distributed energy technologies at the federal level, and would encourage fair and reasonable interconnection policies at the distribution level as well, to the benefit of all electricity consumers."
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