IEEE Power & Energy Magazine - May/June 2016 - 74

The complexity, fun, and the necessity for a distribution system
operator arise from the need to coordinate DER operations to
preserve and improve, not jeopardize, grid reliability.

PV (and wind) variability increases the wholesale market
costs for balancing energy and for regulation. By contrast,
DR from resources like commercial refrigeration, CHP, and
consumer air-conditioning can all be used to mitigate the
duck curve effect and provide balancing energy and regulation service, decreasing the wholesale costs. Emerging technologies such as energy storage and EVs can also favorably
influence wholesale markets. Thus designing the DSO markets to include ancillary services can be important. The DER
penetration needs to be favorable for all wholesale market
conditions, not just total energy. And DER incentives have to
recognize this. An important example is that energy storage
(e.g., BESSs) can be used on the distribution circuit to reduce
peak load (allowing for a deferral of substation transformer
and/or feeder upgrades) and to mitigate voltage fluctuations
caused by PV output fluctuations. The economics of those
two applications, which are typically utility "reliability"
applications, may not be enough to justify storage. But if the
storage can also participate in wholesale market balancing
energy and regulation services, the economics improve. This
is mixing a regulated utility function with a market function and will require some creative regulatory decisions to
see storage deployed. The utility will need to put the costs
of storage, whether utility owned or acquired from a third
party via a capacity market, in the rate base. And whoever
operates the storage-the utility, a consumer, or an investor-will need to access the ISO ancillary markets via the
DSO. The DSO will have to mediate between the reliability
application and the wholesale market application so as to
ensure that no conflicts arise.

Retail and Wholesale Markets
The energy industry has already seen some unintended
consequences during the development of markets as well as
during the adoption of DERs at high levels. As noted in the
article by Kristov et al. in this issue, the early days of the
California markets demonstrated the need for integration of
the energy day-ahead markets with grid ancillary markets and
operations, and this is the case in all of North America today.
The high penetration of PV distributed generation in Hawaii
and southern California and in specific distribution circuits
around the United States (New Jersey, Arizona, Nevada, and
North Carolina) has demonstrated that operational challenges
such as voltage fluctuations and reverse power flows can and
will happen, leading to utilities having to adapt protection and
voltage control systems to high PV penetration levels and even
74

ieee power & energy magazine

to seek the ability to impose limits on total PV penetration on
a given circuit. Some states such as Arizona and Hawaii have
also taken steps to limit feed-in tariffs for PVs to reduce crosssubsidization effects in T&D tariffs or to eliminate net energy
metering programs.
There are two arguments for creating DSOs that complement each other and ultimately interact. One can be stated as
"we have all these DERs-let's integrate them in a market
environment to get greater economic benefit for everyone,
not just the DER owner." The second can be stated as "DERs
can provide benefits in reduced capital investments in T&D
infrastructure and in central generation if done right-let's
create a market environment that will incentivize customers, utilities (if allowed), and third parties to invest in DERs
where they will do the most good." In both cases, a DSO is
needed to organize the market and manage reliability as well
as to interact with the wholesale markets.
These two simplistic restatements of motivation for TE or
a DSO point to a very big difference between the wholesale
energy markets at the ISO level and the retail markets at the
DSO level. When we first implemented wholesale markets,
the entire paradigm of how to economically operate a vertically integrated utility for best economics while maintaining
transmission reliability already existed and was in use at many
vertically integrated utilities; we already had the mathematical
framework, methodologies, and technologies for unit commitment, economic dispatch, and optimal power flow. So, from a
simplistic perspective, all we had to do was change "cost" to
"price" in the math and set up the mechanisms for power plant
owners to bid into a market and settle the financial flows. That
simplistic approach cost tens of millions of dollars and a couple
of years to "get it right." With the DSO-in some cases where
a motivation is to incentivize DER deployment-the resources
don't yet exist, and in no case does the paradigm for integrated
retail energy economics and grid reliability exist operationally
(outside some small scale demonstration projects). So it would
be reasonable to expect unintended consequences to be at least
as interesting as was the case with wholesale market development. There is also the important matters of what it will cost
to implement a DSO at scale and whether the benefits will
outweigh those costs.
A great example of this is the need for reliability and
capacity markets, hotly debated with different approaches
in the different ISOs but accepted as desirable in some
regions. (Technically, a capacity market would be for generation capacity, peak shaving, for instance, on a distribution
may/june 2016



Table of Contents for the Digital Edition of IEEE Power & Energy Magazine - May/June 2016

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