IEEE Power & Energy Magazine - May/June 2016 - 66
The two visions are deliberately drawn as conceptually
distinct to reveal key operational design choices
and derive some observations to help inform today's discussions.
A second key insight has to do with scalability, which
means that the relationship between the TSO and DSO at the
T-D interface can be replicated at lower or higher levels or
layers of the system. For example, the layered paradigm can
be applied to the interface between the DSO and a microgrid
connected to a distribution circuit, and yet again between the
microgrid and a "smart building" that is one of the components
of the microgrid. At each layer, the optimizing entity (TSO,
DSO, microgrid, or smart building) only needs to manage its
interfaces with the higher and lower layers without needing to
be concerned with the specific components internal to those
other layers. The value of such scalability is that it allows for a
rigorous coordination framework, whereby the behavior of the
system components can be coordinated to ensure predictable,
reliable performance of the whole system.
Distribution-Level Locational Pricing
The idea of applying LMP, common to today's ISOs and
RTOs, to distribution systems is being discussed in the industry. There are two questions that bear on the grand central
versus layered discussion. First, when would we want to
implement an "LMP+D" regime where the price at a specific location on the distribution system equals the wholesale market LMP at the T-D interface plus a "D" factor that
reflects distribution-system losses, congestion and other characteristics? Second, more generally what are the challenges,
limitations, and potential net benefits to developing a distribution-level locational pricing scheme for energy and capacity
provided by DERs and responsive end-use customers?
The simple answer to the first question is that the LMP+D
approach may be appropriate for the grand optimization paradigm but would not make sense for the layered optimization.
LMP+D pricing is derived from the ISO/RTO market simply
by extending the wholesale LMP at the T-D interface into
the distribution grid to specific locations of DERs and end
users. This could be done by modeling the distribution grid in
the central optimization algorithm, but this would require an
accurate electrical model of the distribution system and realtime state information, a complex and expensive enhancement that is not yet possible. Or this could be done more simply by, for example, applying statistical pricing factors (such
as loss factors) to determine the D adjustments appropriate
to specific feeders or nodes on a feeder. A pricing method
derived from the wholesale market intuitively makes sense
for the grand optimization paradigm, where most DERs are
bid into and dispatched by the wholesale market.
66
ieee power & energy magazine
In the layered optimization, however, the DSO is balancing supply and demand within the LDA using the diverse
mix of available DERs within the LDA plus interchange with
the transmission system. Thus the LMP at the T-D interface
is only the price of imports and exports at the interface,and
as such is only one factor affecting the cost of energy within
that LDA. Under the layered paradigm, rather than pricing
based on wholesale LMPs, the pricing methodology should
reflect the mix of resource types and customers within the
LDA as well as the characteristics of the distribution grid
itself, such that the marginal price at a location reflects the
least cost of serving an additional kilowatt-hour of load at
that location. In particular, the effect of the wholesale LMP
in the locational price should go to zero continuously as the
LDA's volume of net imports or exports approaches zero.
The second question goes to whether or in what circumstances some form of distribution-level LMP is the best way
to facilitate DER operation and investment. There has been
much debate over the years about whether wholesale LMPs
provide effective incentives to finance generation or grid
investment. In general it seems that generation investment
requires long-term power purchase agreements and capacity
payments, while transmission investment proceeds mostly
through central planning and rate-payer funding. If the
policy objective is to promote DER investment, there is no
apparent reason to believe that distribution-level locational
spot prices would have any greater success. Rather, the demonstrated value of wholesale LMPs has been to provide nearterm scheduling and operating incentives consistent with
grid conditions. By extension, then, this is what pricing on
the distribution system should achieve.
If the goal is limited to near-term operating incentives,
the design of a pricing paradigm to support reliable distribution system operation must address questions of spatial and
temporal granularity. Control theory for large complex systems tells us that there are certain situations where markets,
which rely on economic signals to entities that may voluntarily respond, are not sufficiently effective to maintain reliable system operation. Such situations are typically defined
by the rapidity of the required response or the signal refresh
cycle, combined with the number of entities that receive and
must respond to the signal. Such situations are better managed via controls, where the control signal elicits a hardwired response that is predictable and consistent as long as
the control system functions properly. In fact, it has been
clearly demonstrated in all ISO and RTO markets on the
may/june 2016
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