Avenue Oakland, California
94611 510 451 1727
Distribution Wheeling Amendment to AB48x
To Accompany Amendment to AB48x providing for Distribution Wheeling tariffs by Utility Distribution Companies and establishing jurisdictions and guidelines for the measurement of Distribution Wheeling transactions.
This amendment language would facilitate the development of Distributed Generation in California generally. This is of particular concern to municipalities seeking the Community Choice option in the context of the state’s energy crisis. Specifically, because of volatility in both the wholesale market for electricity and in the price of natural gas, municipalities are particularly concerned with developing local generation to improve community-wide “grid efficiency” to reduce community dependence on central generation, including “peak shaving,” “peak shifting,” and other measures that involve generating power from a Distributed Generation facility (such as a rooftop solar panel) at one location on a distribution system to a peaking load point (such as an industrial motor or air conditioner) at another location in the same distribution system. The California ISO have indicated its interest in metering and thus billing distributed generation as a “transmission” transaction as if it used the transmission lines outside the distribution system. The FERC has even indicated an interers in asserting jurisdiction over distributed generation as an “interstate commerce.” This amendment to AB48x would meter distribution generation transactions at the distribution substation and establishes clear jurisdictional guidelines for metering and billing such transactions. The amendment also direct the distribution utilities (UDCs), and public power systems that have elected to participate in the market, to file tariffs (standardized prices) for such distribution wheeling.
Distributed Generation, or “DG”, represents a significant change in the way electric energy is produced and distributed. Occurring in much smaller sizes but in much greater numbers than traditional “Central Plant” generation, DG is intimately related to the loads it is intended to serve, and to the local communities in which those loads are located.
Central Plant generation requires immense initial capital investment and drives the design and operation of the electrical transmission and distribution systems towards maximum crude efficiency in a one-size-fits-all architecture.
The emergence of DG provides greater choice in the development of electrical generating plant and allows the transmission and distribution systems to provide greater efficacy to a wider variety of electrical energy needs with little or no detriment to overall efficiency.
However, the novelty of DG presents certain rate design challenges. First, traditional rate design developed in an era when most if not all generation was provided by the same entity that provided the transmission and distribution, or “T&D”, facilities, and so placed all of the cost responsibility for T&D on end-use customers, bundled together with generation costs. Initial steps of electric service industry restructuring merely unbundled generating costs from T&D costs.
Second, when there was no relationship between the configuration of generating plants and the loads served, one had little to do with the costs imposed on the system by the other. With DG, increasingly complex arrangements are possible for what used to be called “end-use” customers, who may now self-generate a portion of their own electrical requirements or even generate beyond their own requirements and provide off-peak energy, or even on-peak capacity, to the greater system. Loads with high reliability requirements especially may require multiple-redundant on-site capacity, as much as 300% of base load, resulting in substantial on-peak capacity for sale back into the grid.
Third, customer needs are changing, too. Where most business activities may have once been conducted upon a single premises, many business activities have adopted “campus”, “park”, or similar physical layouts, often incorporating public thoroughfares within the outlines of the business project. Traditional utility regulation did not provide for the private transfer of energy across public rights of way. While recent provisions for “direct access” energy transaction have changed the environment somewhat, T&D rate design still tends to presume that all energy comes from large Central Plants, engaged in interstate commerce over interstate transmission facilities. So-called “micro-grid” developments are rapidly challenging those assumptions, by creating and managing diversity of generation and demand profiles.
DG changes these fundamentally. Smaller, non-traditional generators are increasingly using the distribution system in ways that are not meaningfully different from its use by traditional, end-use customers. DG can and is increasingly developed around the needs of a very small number of customers, in ways that, from the perspective of the distribution system, are not meaningfully different from an aggregation of a small number of end-use customers. Entire ensembles of loads and DG are being developed around local microgrids that seek to present themselves to the public infrastructure as a single entity, identifying and capturing within the project the value of the generation and demand diversity.
Transmission and Distribution
To serve the needs of Central Plant generation, those large power plants are interconnected to high-voltage, high-capacity, interstate transmission lines. These facilities are usually connected in multiple-, parallel paths to comprise an electrical “network”. Electricity cannot easily be directed down a specific path, but spreads out among all parallel loops between its source and its destinations. This phenomenon is called “loop flow” and is the physical basis for the relationship between high-voltage transmission lines and federally-regulated interstate commerce.
From various nodes along transmission lines, transformers at substations connect higher-voltage, higher-capacity lines to, usually, a greater number of somewhat-lower-voltage, somewhat-lower-capacity lines. Eventually, power is conducted from Central Plants, through any number of voltage levels, or so-called transmission, subtransmission, primary distribution, and secondary distribution, until it gets to the so-called “end-use” customer.
At some point in this voltage hierarchy, usually between subtransmission and primary distribution (and, often, just between federal and state jurisdictions), multiple paths cease and there is only one path downward to any one end-use customer, a so-called “radial” configuration. From any one of those such points, downward in the voltage hierarchy, where the configuration is radial, we call it a “local distribution system”.
(Networked distribution systems do exist, usually only in central business districts, but they are special facilities, not within the scope of distribution wheeling for the foreseeable future.)
While these local distribution systems are exclusively operated radially, they are often constructed in the form of segmented, switched loops —albeit “loops” with at least one of the segment switches always open. These switched segments allows the utility company to rapidly reconfigure a local distribution line in cases of construction, routine maintenance, or emergency repair.
Sometimes, when routine work or emergency repair may be needed in a portion of one “local distribution system” that is physically adjacent to another, distinct, local distribution system (that is, one not served from the same transmission facility), and a switched segment of a line on one system may be temporarily connected to the other local distribution system. This is a short-term, temporary reconfiguration of the systems, made for the convenience of the system operators while performing maintenance, construction, or repair work, and is distinct from permanent reconfigurations of distribution lines that may be occasioned by persistent changes in load distribution or growth.
Wheeling is the utility term of art for any transportation of energy among parties other than the T&D operator. Traditionally, this referred to the transportation of energy from an independent Central Plant operator, across an interstate transmission system, to a remote customer.
With the advent of direct access and community choice options on the part of end-use customers, together with the potential for DG operators to serve those customers, it is possible that both the generation and the loads may all exist on the same local distribution system. Indeed, the nature of DG tends to ensure that this will be the case in the future. The questions naturally arise, then, first, does such a transaction make use of the interstate transmission system, and second, if so, what costs are imposed which should then be recovered from the parties to such a transaction?
The short answer is that, while distribution wheeling may make use of the interstate transmission system, it does so in a way that imposes very little or nearly no cost on that system. The reason for the negligible cost of distribution wheeling lies with modern electronic control systems.
Distribution Wheeling As Aggregation
In many respects, distribution wheeling is a modern form of customer load aggregation, but where some of the “customers” may in fact be small generators. When the total local energy production within the distribution wheeling transaction is equal to the total local energy consumption, then there is no net purchase of energy over the interstate transmission system.
We do not believe, recent California ISO interpretations notwithstanding, that federal law specifically requires interstate transmission charges to be derived from gross determinants, nor charged directly to end-use customers.
Nor do we do not believe that federal law expressly prohibits the designation of an intermediary “transmission” customer; nor the accumulation of incidental charges, necessary for the operation of the distribution system, into the distribution revenue requirement; nor the allocation of those charges to an entire class of customers, as opposed to customer-specific charges.
Metering, monitoring, and instrumentation
Hourly interval metering is rapidly becoming the standard methodology for determining billing measurements for electric service. For the bulk of customers, the transition from monthly to hourly interval metering must be managed to minimize systematic costs and individual customer impacts. It is appropriate to accelerate any customer to interval metering when the customer’s circumstances will allow a net benefit over costs over a relatively short period of time. Distribution wheeling appears to be one of those cases.
Both state interim standards and evolving national standards for the interconnection of DG at distribution voltages addresses monitoring or instrumentation for safety purposes. Nothing in this legislation should undermine such standardized practices.
However, in the past, utilities have been criticized for imposing superfluous instrumentation requirements on customers attempting to self-generate all or a portion of their own requirements. This legislation would provide that, other than for interval metering or standardized safety monitoring, no party to a distribution wheeling transaction should have any instrumentation requirements greater than would be imposed on a non-generating customer whose load was the same size as the largest rated party to the transaction.
Most customers have a 30- or 60- minute interval metering requirement. A few large customers may have a 15-minute interval requirement, and a very few customers with unusual requirements, such as large arc welders, may have a 5-minute interval requirement. Large generators have several characteristics that make extra monitoring and instrumentation appropriate, but all appropriate requirements for the monitoring of DG interconnected at distribution voltages are fully specified in the existing state interim standard and the imminent national standard, and are addressed elsewhere for generators interconnected to the transmission system.
For any given transaction the metering requirements for all participants, loads or generators, in addition to the standardized interconnection requirements for the generators, would be determined by the most restrictive of the participating loads. No further requirements are to be imposed than as specified herein.
Rate Design Issues
Gross load and gross generation metering techniques that were appropriate for traditional Central Plant generation serving traditional end-use customers tend to severely overstate the costs imposed on the T&D system by distribution wheeling transactions. Actual costs likely to be imposed on the transmission system, while not necessarily zero, would be very small. First, the distribution wheeling model is predicated on no net import or export outside the participating parties to the transaction; thus, no bulk interstate energy is being purchased.
Second, distribution wheeling transactions can control, and thus act to minimize, their use of ancillary services. Just like a single customer with on-site generation, a distribution wheeling customer should be able to take service with, or without, backup; that is, “firm” or “nonfirm” service. If a DW party takes “nonfirm” service, and their generation goes out, they either provide their own backup or go dark, just like any other non-firm customer. There are certain other ancillary services, such as system control, that DW parties would benefit from, but these, are presently bundled together with bulk power purchases, and charged for by the hourly-metered energy usage. By the prevailing transmission rate design practices, no charges would be due for these services as long as no net energy was transported over the interstate transmission system. The California ISO has displayed a relentlessness to avoid accommodating DW, and so several rate design principles, fully consistent with prevailing practices but designed to prevent novel, anti-DW reinterpretation, are provided.