Local Power
4281 Piedmont
Avenue Oakland, California
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Fact Sheet
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.
General Summary
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
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.
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