IEEE Power & Energy Magazine - May/June 2016 - 78

DSO operations. Some utilities have advanced distribution
management systems, intelligent electronic devices, and
smart switches and reclosers operating in substation and
feeder automation schemes with these capabilities; others do
not. A larger challenge is how to communicate with DERs.
Dedicated utility supervisory control and data acquisition
communications are likely to be prohibitively expensive, and
there is the question of whether DERs will support them.
Possibilities include the use of existing utility fiber and wide
area networks with advanced metering infrastructure (AMI)
or cellular technology for the last leg or, more prominently
in the TE discussions, the IoT. Here, a number of issues have
to be addressed.
✔ Consumer privacy and commercial privileged information protection. Presumably, market participants
will agree to reasonable conditions for participation.
✔ North American Electric Reliability Corporation
(NERC) physical and cybersecurity. DERs that are
providing reliability-critical ancillary services may be
viewed as critical infrastructure. Whether AMI or IoT
technologies will meet NERC critical infrastructure
protection standards in coming years is uncertain.
✔ Performance requirements for certain ancillary services and reliability functions where Internet latency
under high loading may not be tolerable
✔ And, of course, whether sufficient standardization
and interoperability will allow end element to plug
and play. Standards such as open automated demand
response (are an excellent start. But as the IoT blossoms, we have to keep regular desktop printers in
mind, which are nominally easy to set up and install,
but the plethora of models (all with manufacturer
valued-added features and complexities) still makes
these a source of consumer frustration.
Highly automated/easy-to-use processes for participant
registration and validation-not only the hardware but also
the software-must be plug-and-play with minimal DSO
labor required and near zero hassle for the consumer.
✔ Ownership of the DERs and the communications.
Many consumers lease PVs from installers/developers, and the panels may include general packet radio
service for the convenience of the operator, for maintenance and performance monitoring. This begs the
question of who is the market participant. Is it the solar developer/operator or the prosumer?
✔ Ownership and operation of the DSO itself. Due to
the tight linkages to grid reliability and the inevitable need for capacity and reliability markets for zero
marginal cost resources providing services, a strong
case can be made for distribution utility responsibility
for the DSO. Also, there are no linkages or synergies
across utility distribution systems operationally (other
than through the wholesale markets) so no argument
for a separate operator above the utility. This leaves
the question of utility ownership of DERs versus
78

ieee power & energy magazine

utility operation of the DSO. On the one hand, utility
ownership of DERs may "seed" things and lead the
way to liquidity; on the other hand the inevitable worries about biased outcomes exist, thus utility participation in DSO markets with utility owned DERs will
have to be transparent in real time to other participants and overseen by regulators.
This list is only preliminary, but it highlights the need
for a significant amount of work to address the details.
Once the market design is agreed upon and the communications/control infrastructure is in place, implementing
a DSO may be a manageable effort today. But getting to
that point may be the hard part. Policy and regulatory decisions will influence market design that in turn will influence infrastructure needs, which are major cost elements
and will affect DER adoption, market participation, and
DSO success overall.

Conclusions
Personally, as engineers who believe that PVs, EV, BESSs,
and the IoT and smart end use are inevitable and all can
be good (provided that utility practices evolve accordingly), we need to get the DSO design mostly right the
first time out of the box. The complications and possibilities for adverse effects can be mitigated and avoided and
should not be reasons to say "slow down" or "no more"
to DERs and to their beneficial integration in the markets
and operations. Rather, we need to understand how to realize the possible benefits and design markets and systems
accordingly. We believe that rigorous cost-benefit analyses
including all the market effects, utility cost and investment
effects, and, most importantly, customer and third-party
adoption rates and market participation are a high priority,
all of which must be tailored closely to each region and
jurisdiction. Static analyses are not going to be sufficient
given that the dynamics of technology adoption, customer,
and third-party investment, and prosumer behavior all will
interact over time. A dynamic cost-benefit model that can
capture these effects is needed. That dynamic model could
also examine the wholesale-retail interaction dynamically
and illustrate needed protocols and infrastructure as well
as market design issues.

For Further Reading
K. L. Anaya and M. G. Pollitt, "Distributed generation:
Opportunities for distribution network operators, wider
society and generators, Energy Policy Research Group,"
Cambridge Univ., CWPE 1505.
K. DeIullis, F. Farzan, J. Harrison, and R. Masiello,
"Markets 3.0 retail wholesale convergence," in Proc. IEEE
Innovative Smart Grid Technol., Jan. 2012.

Biographies
Ralph Masiello is with Quanta-Technology.
Julio Romero Agüero is with Quanta-Technology.

p&e

may/june 2016

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