IEEE Power & Energy Magazine - January/February 2020 - 40

Lessons Learned
The collaboration between HCE and its partners is an excellent example of multiple stakeholders working together for
mutual benefit and maximum value. Initiatives like these
can help offset the cost for smaller utilities. Although there
may be initial uncertainty concerning its benefits, the return
on investment for executing an ADMS system is clear, in
HCE's experience. For example, NREL studied the impact
of DERs on HCE's system. The study found that, compared
to a base case in which there was no aggregated control of
DERs, electricity costs for all-electric residential consumers
could be reduced by 20.7% when ADMS-controlled DERs
were combined with a time-of-use rate. This would also
reduce local impacts on the distribution grid. It can also be
difficult to justify the ongoing cost, but once the system is
up and running, the positive impact on resilience, reliability, and renewable energy options can be positive by comparison. Applying for a grant or participating in a research
project can offset some of the cost, but for a smooth and successful project, consumers or members must see the benefits
and support the initiative.
HCE advises other small utilities to think big but start
small and be patient. Utilities should first build a foundation of validated data and a good system model and then
integrate that information for better system visualization
and system awareness. Once these foundations are complete, utilities can comfortably add applications such as
switching validation, outage restoration, and forecasting.
Using these applications, utilities can establish a system
capable of controlling segmented microgrids that alternate
between local optimization and participation in broader
regional optimization.

Objective 3: Achieving Appropriate
Operational Performance and Financial
Returns for Grid Modernization
Initiatives, Including Digital
Transformation
Unprecedented advances in technology and new levels of
customer empowerment are introducing new devices and
software capabilities, which are accompanied by higher customer expectations. From smart meters to cloud-based software to enabling the use of mobile devices to distribution
automation and more, the industry norm is moving inexorably toward a smart grid. Small utilities are not exempt from
the need for grid modernization.
Just as grid modernization is inevitable, the advancement
of digital transformation into every aspect of utility operations is equally relentless. Every new device, application,
and piece of hardware is designed with the digital consumer
in mind, be they human or machine interface.
This puts an additional burden on decision makers to identify, prioritize, and budget for a capital investment plan that
aligns infrastructure and software with long-term goals. Utilities must address the requirements of regulators, commercial
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customers, and residential consumers. To further complicate
matters, they must also balance technology investments with
systems and human resources at a time when a greater number of employees are retiring than being hired.
The tasks ahead may seem daunting, but the financial and
operational rewards of embracing grid modernization and
digital transformation are clearly helping utilities to accomplish the following:
✔ improve decision making, resulting in more resilient
and reliable power delivery
✔ increase customer satisfaction by providing access to
online interactions and information
✔ attract and quickly provide the incoming younger
workforce with a modern user experience and automation capabilities
✔ increase productivity and decrease outage durations
using applications that automate outage detection and
restoration activities.
Vendors can help utilities determine the technology that
will have the most impact in the right areas and build an
affordable road map that delivers the greatest overall return
on investment. To do so, utilities must select vendors whose
product development plan is in sync with their needs, partner
with them over the long term, offer advisory support, and
support them in achieving their goals.

Case Study 3: Lessons Learned From
Peninsula Light Company
Utility Spotlight
✔ Who: Peninsula Light Company
✔ What: the second-largest member-owned cooperative

in the Northwest United States
✔ Where: Western Pierce County, Washington
✔ Territory: 290 km2, including rugged terrain
✔ Number of customers: 32,000 residential and business
electric consumers and 3,230 water consumers.
Peninsula Light Company is halfway through its ADMS
implementation plan, having begun that effort in 2016.
It was part of an ongoing reliability improvement commitment made by its chief executive officer and board
of directors in 2005. Its ambitious goal was to move
from the fourth quartile of reliability to the first quartile, as compared to all U.S. utilities and using IEEE
reliability benchmarking.
In 2009, Peninsula Light Company redoubled its efforts
and applied its funding toward the conversion of overhead
power lines to the underground replacement of end-of-life
direct buried cables and the installation of tree wire, plasticcoated overhead conductors used in heavily wooded areas
prone to limbs and branches falling. Although 70% of the
total system is now underground, 50% of the three-phase
backbone remains overhead, surrounded by massive fir trees.
It was not practicable to convert the backbone to underground, so Peninsula Light Company looked to automation
january/february 2020

IEEE Power & Energy Magazine - January/February 2020

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