IEEE Power & Energy Magazine - January/February 2020 - 39

Holy Cross Energy (HCE) is in the early stages of its ADMS
implementation. Ultimately, the utility aims to increase its grid
reliability, improve power quality, increase its use of renewable
energy resources, secure data, and become more resilient to
natural disasters.
HCE views its grid modernization initiative as a tool to
balance the values of its members. In some cases, members want maximum reliability for the lowest cost possible
and are unconcerned about the sources of electricity. Other
members are eager for renewable energy options, even if
this puts upward pressure on costs. HCE realized it would
need to innovate to incorporate more DERs and manage load
using the same dexterity with which it has managed supply.
An ADMS system was used to perform the necessary calculations and commands.
To date, the utility has used its SCADA system to monitor power flows and voltages at substations and reclosers,
examine real-time data, and increase utility control over
assets, including renewable energy sources. HCE has also
deployed SCADA control of DERs and is using short-term
load forecasting software to help manage and predict system loads. HCE sees a need for short-term load forecasting
to take advantage of the synergy between renewable energy
and flexible loads, including plug-in electric vehicle charging. The utility can leverage its awareness of periods prone
to renewable oversupply to optimize consumption management. HCE also uses short-term load forecasting to send
real-time load data to its energy services provider.
The ADMS will need to integrate current data, measurements, and control applications from a variety of vendors.
The utility plans to operate the ADMS from a single, centralized platform that will facilitate the seamless addition
of new applications. Without the ADMS, HCE's operators
would be forced to use multiple, noncentralized, cloudbased platforms to control behind-the-meter (BTM) DERs.
Navigating multiple proprietary software interfaces to
accomplish a coordinated objective is inefficient and convoluted. HCE decided the best way to develop a long-term
DER strategy was to prioritize the installation of a unified
platform that would aggregate all measurements and allow
for fast and accurate decision making.
Although the utility was confident in the idea of improving visualization and system control, it faced challenges in
funding the project and assigning resources from its relatively
small team. Because HCE is a small cooperative, employees
have to be nimble, i.e., able to perform multiple tasks using
diverse skills. The utility does not have a dedicated SCADA/
ADMS role, so system management is just one of the many
functions taken on by team members who also manage the
geographic information system (GIS) and system operations.
To address these challenges, HCE applied for a U.S.
Department of Energy High Impact Technology Project.
The National Renewable Energy Laboratory (NREL), the
National Rural Electric Cooperative Association, Heila Technologies, Survalent Technology, and HCE are identifying
january/february 2020

the requirements and means to achieve ADMS and DERs
interoperability. Specifically, the project aims to enable
smaller utilities to incorporate DERs at scale into its distribution network.
The collaborative project will identify algorithms and
communication protocols that small utilities can use to
monitor and control DERs without requiring expensive
investments in new technology to achieve interoperability.
The project will test the integration of new algorithms and
communication protocols with legacy and advanced applications to provide real-time grid services and increase DER
hosting capacity. To ensure efficient performance in reallife operating scenarios, advanced control algorithms will
be evaluated using data from HCE's distribution management system. The project will assess use cases in a realistic
environment, which includes megawatt-scale hardware testing in the lab and the 250-kW field deployment testing of
HCE's system.
HCE has been preparing for grid modernization in small
stages for years. It began with the use of a GIS, the subsequent
installation of smart devices on reclosers and voltage regulators, and HCE is now deploying line sensors, automated
switching equipment, and distribution monitoring meters that
utilize Distributed Network Protocol 3. Potential next steps
include installing local coordinators on switchgears or transformers that will manage BTM (or even become the meter)
and using aggregators that will make DERs more flexible.
The utility has also established three new tariffs: a DER
service agreement to help with the upfront cost of installing
DERs, a peak-time rebate program for individuals who wish
to control their own energy usage in exchange for incentives
during peak events, and a distribution flexibility program for
members who are willing to let the utility optimize and control their DERs.
As a result of the DERs interoperability project, HCE
hopes to add more load flexibility controllers for load deferral
and demand-response applications. These will help manage
peak loads by deferring energy usage and dispatching storage devices integrated with renewable energy supply. The
utility is also encouraging the establishment of residential
nanogrids to make communities and homes more resilient,
efficient, and flexible. Future plans include the application of
a BTM battery management system and load control breakers. Examples of flexible operations provided by very small,
locally controlled systems include the option for a flattened
load shape, coincident peak minimization, or storage-use
optimization for microgrids or broader system resiliency.
Collaborating on this research will help the utility overcome the financial and resource challenges of enacting
DERs and also will reduce the financial and project administration risks. HCE's ability to perform testing in the U.S.
Department of Energy's primary laboratory for renewable
energy and energy efficiency research prior to implementation in its own grid has enabled the pilot field deployment to
run smoothly from the start.
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IEEE Power & Energy Magazine - January/February 2020

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