Toward a New Grid Operating Paradigm 2013

EEI Webinar 3 Paper draft
1
Toward a New Operating Paradigm: Reliable Integration of DER
P. De Martini, D. Grueneich, M. McGranaghan, J. Taft and J. Taylor
Introduction
The US electric distribution system may need to integrate over 300,000 MWs of distributed energy
resources by 2025.1
This number would roughly equate to an average of over 30% penetration on the
typical distribution feeders likely to be affected – twice the amount allowed under many distributed
generator integration standards.2
This is a fundamental shift from traditional distribution systems that
deliver power from controllable centralized generation to meet highly predictable aggregate demand.
The emerging distribution system of the future is far more complicated given tremendous energy
variability and changing customer relationship – “one hour a consumer and the next hour a producer.”
Customer adoption of on-site generation and other distributed energy resources is a fundamental driver
of distribution network transformation. The pace of adoption has accelerated in recent years, for
example, in 2012 commercial and residential customer solar photovoltaic systems combined came
online an average of about one every seven minutes.
This future distribution system involves development and implementation of a sophisticated yet simple
architecture to reliably, safely and securely integrate advanced technologies and control systems to
accommodate multi-directional power from distributed and variable generation. This future system
development is being done concurrently as the existing distribution “Grid 2.0”3
is being upgraded at the
rate of about $22 billion a year. This transformation is not unlike converting a 737 passenger jet into an
aircraft with the advanced fly-by wire sophistication needed to fly an inherently unstable B-2 bomber -
without landing the plane and continuing to fly reliably and safely. Not surprisingly, questions remain on
how to a) reliably integrate distributive resources, b) develop effective market designs and architectures
to address operational challenges, and c) evolve regulation to address integration, innovation and
investment, and reasonable cost allocation. This paper highlights these issues drawing on the
presentations and discussion on the Edison Electric Institute’s webinar held November 27, 2012.
Customer Adoption of Distributed Energy Resources
While residential solar adoption has garnered significant attention, the larger customer market for
onsite generation and distributed resources is the commercial sector. In the US, businesses,
institutional and government facilities already have over 80,000 MWs of combined heat and power
systems installed and the White House recently announced a goal of increasing that figure by 50% in
2020.4
Additionally, nearly 3,000 MWs of solar PV is expected to be installed in 2012 with another 7,000
1
Solar power: Darkest before dawn, McKinsey & Co., May 2012 and US Executive Order, Accelerating Investment
in Industrial Energy Efficiency, August 2012
2
Grid 2020: Toward a Policy of Renewable and Distributed Energy Resources, Caltech Resnick Institute, 2012
3
EPRI Staff, Needed: A Grid Operating System to Facilitate Grid Transformation, EPRI, July 2011
4
US Executive Order, Accelerating Investment in Industrial Energy Efficiency, August 2012

2
megawatts over the next five years. What are the factors driving commercial customer decisions?
According to Ernst & Young (E&Y) in their recent cleantech report surveying 100 global corporations5
,
the reason given is that “energy strategy has become an integral aspect of managing key financial,
energy security, brand, regulatory and competitive risks.” E&Y summarized five key factors:
• Energy expenditures are becoming a growing
share of operational costs as fossil fuel-based
energy prices increase and price fluctuations in
traditional energy sources impact the bottom
line.
• The Fukushima disaster in Japan and political
turmoil in the Middle East highlight energy
availability risks.
• Increased consumer focus on sustainability is
changing how industry leadership is being
defined.
• Long-term carbon penalties and license-to
operate risks arise as governments focus on
energy efficiency and environmental objectives.
• The new reality of the resource-constrained,
low-carbon economy changes the basis of competitive advantage.
In this context, it is not surprising that at over 75% of the firms surveyed, final decisions on energy mix
strategy are made by C-level officers. Also, one-third of the multi-national firms expected to meet a
greater share of their energy needs through self-generation over the next five years. For example, the
Solar Energy Industries Association (SEIA) reports6
that the Top 20 corporate solar users’ installations
generate an estimated $47.3 million worth of electricity each year and reduced business’ utility bills by
hundreds of millions of dollars annually. The following quote from General Motors in the E&Y report
illustrates this trend;
“…our focus on renewable energy doesn’t stop at the sun. By 2020, our goal is to promote the use of all
forms of renewable energy by using 125 megawatts across our entire corporate footprint.” said Mike
Robinson, GM vice president, sustainability and global regulatory affairs
The distribution system implications of these global corporate energy strategies are clear when
combined with similar US Federal and state government energy strategies. The most prominent is the
Department of Defense energy strategy to reduce “reliance on a fragile commercial electricity grid [that]
places continuity of missions at growing risk”7
. DoD’s plan includes a legislated and Executive ordered8
5
Cleantech Matters, Global competitiveness Global cleantech insights and trends report, Ernst & Young, 2012
6
Solar Means Business: Top Commercial Solar Customers in the U.S., SEIA and Vote Solar, 2012
7
Defense Science Board, “More Fight – Less Fuel,” DoD, February 2008
8
US Federal Legislation and Executive Orders; EPAct 2005, EISA 2007, NDAA, EO 13423, EO 13514
Figure 1. Campus Microgrid

3
37.5% reduction in energy consumed by their 2.2 billion square feet of facilities by 2020 and to produce
or procure 25% of the resulting energy needed from renewable resources by 2025. This has spurred
significant clean energy development effort at DoD, as highlighted by a 2012 DoD feasibility study9
of
solar PV installation potential at military bases in the California and Nevada deserts. The study
concluded that using only 4% of the facilities’ area it was possible to generate “7000 megawatts (MW) of
solar energy -- equivalent to the output of seven nuclear power plants” and “more than 30 times the
electricity consumed by the bases.”
The example in Figure 2 below illustrates a typical business case for on-site generation/microgrid today
that is largely based on tax and incentive benefits avoiding otherwise applicable retail power rates,
reliability improvement, environmental objectives and increasingly the opportunity for new revenue
streams is playing a role. Typical benefit categories are:
• Tax and incentive benefits from Federal and state programs
• Reduced energy costs both in terms of lowering net energy consumed, and demand charges
• Protection of business revenue through improved operational reliability and disaster recovery
• Hedge against volatile energy prices including electricity prices and for fuel switching CHP
systems that accept a variety of fuel sources (e.g., natural gas, biogas, coal, biomass)
• Offset capital costs for CHP when installed in place of boilers or chillers in new construction
projects, or when major HVAC equipment needs to be replaced or updated.
• Organizational environmental objectives
• Incremental revenue streams from sales of excess energy and ancillary services
Figure 2. New York Microgrid Business Case
9
ICF International, Solar Energy Development on DoD Installations in the Mojave & Colorado Deserts, DoD Office of
Installations and Environment, January 2012

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As another example, the DoD solar study also identified that private development of the solar potential
on those desert bases with no capital investment requirement from DoD, and that the development
could yield the federal government up to $100 million a year in benefits from rental payments, reduced
cost power, in-kind considerations, or some combination.
Grid 3.0
Interconnection
An ongoing challenge for all stakeholders is the lack of sufficient interconnection rules, technology and
standards to enable the scale of DER adoption and seamless integration and islanding during power
outages. Today, most on-site generation facilities are not able and/or allowed to seamlessly separate
into an islanding mode to provide uninterrupted power to the customer’s facility during a power outage.
For example, in Stanford, Connecticut several large global financial trading floors have remarkable
distributed telecommunications and computing capabilities in the event of disruptions to these systems,
but the lack of a similar capability for seamless power operations between the grid and their onsite
generation leaves them exposed to outages during system outages. In another example, the University
of California, San Diego which has a renowned campus microgrid took over 6 hours to transfer its
operations to an island mode after an extensive outage due to a substation failure last year. In the wake
of the major natural disasters over the past decade, including Hurricane Sandy, there is increased
urgency resolving the regulation and technical issues to safely and affordably integrate distributed
power so that they can provide uninterrupted power.
Figure 3. Local Energy Network
Grid 3.0 Operating System
As desirable as seamless integration and islanding is to most, there are real technical and safety issues to
resolve for specific projects and for the system at scale of expected adoption. To accomplish this goal
EPRI identifies the need for a Grid 3.0 operating system as 10
:
10
EPRI staff, Needed: A Grid Operating System to Facilitate Grid Transformation, EPRI, 2011

5
“The grid operating system must monitor, protect and automatically optimize the operation of its
interconnected elements – from the central and distributed generator through the high-voltage network
and distribution system, to industrial users and building automation systems, to energy storage
installations, and to end-use consumers including their thermostats, electric vehicles, appliances, and
other household devices. Tomorrow’s grid operating system must manage a two-way flow of electricity
and information to create an automated, widely distributed energy delivery network. The grid operating
system must facilitate high levels of security, quality, reliability, and availability of electric power;
improve economic productivity and quality of life; and minimize environmental impact while maximizing
safety.“
Paraphrasing EPRI, achieving Grid 3.0 requires development of an ultra-large scale architecture which
“can facilitate the informational, financial, and physical transactions necessary to assure adequate
security, quality, reliability and availability of power systems operating in complex and continually
evolving electricity markets.” DoE’s GridWise Architecture Council (GWAC) defines transactions in this
context as “techniques for managing the generation, consumption or flow
of electric power within an electric power system through the use of
economic or market based constructs while considering grid reliability
constraints.”11
Such a transactive energy framework is focused on the convergence of
multi-party business and grid operational objectives and constraints. Not
just markets, but also a broader integrated cyber-physical control system
to ensure reliable electric services. Also, not “Prices to Devices”, but
coordinated and federated engineering-economic signals aligned to
differentiated services across a broad time range. The term “transactive”
comes from considering that decisions are made based on a value. These
decisions may be analogous to or literally economic transactions.12
EPRI’s concept of Grid 3.0 provides a useful “perspective on how to manage transactions given the
nature of the existing and emerging distributed, heterogeneous communications and control network
combined with the extensive use of new innovations on the power system. What is needed is an
architecture that allows future developers to access this framework as a resource or design pattern for
developing distributed software applications, taking into account the core concepts of interoperability
and support for multiple operational criteria including business rules.”13
Ultra-Large Scale Architecture
It is becoming very clear that the industry and researcher need to address the architectural and
engineering issues related to modernizing a grid to support the scale and scope of the resources
envisioned in existing legislative and regulatory mandates in many parts of the developed world. In
addition to EPRI’s design scope, Cisco has identified the need to consider the rise of social networks in
11
GridWise Architecture Council, Transactive Energy Workshop Summary, Summer 2012
12
Grid Interop Foundation Session presentation, GWAC, December 2012
13
EPRI staff, Needed: A Grid Operating System to Facilitate Grid Transformation, EPRI, 2011

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shaping commercial business and the expectation of a prominent role in customer engagement and
commercial relationships.14
Therefore, architecture must address the integration of four networks:
1. Electric network with its inviolable set of physical rules
2. Information and communication networks
3. Energy Markets, especially participation of customers and merchant-provided DER services
4. Social networks as grids become interactive with customers and their smart devices
Earlier efforts to create reference “smart grid” architectures have been based largely on enterprise IT
principles – effectively “Grid 2.5” type architectures. The industry recognized gap is the need to
consider the control of the cyber-physical system based on control system theory and practice. Without
new control architecture, the grid of the future will not scale to support the policy mandates already in
place. Cisco describes the architectural design thesis for Grid 3.0 as:
“Given highly volatile and dispersed resources and physical constraints across the grid, provide a unified
multi-tier control schema that simultaneously optimizes operation across all parts of the power delivery
system, from the markets, balancing and operational levels to the transactive and prosumer level.”15
It is important to look at multiple levels in the entire power delivery chain not just distribution
operations. Traditionally those layers were individually controlled with limited control between the
transmission to distribution and distribution to customer layers. This was because power flowed from
transmission through distribution to customers – so in effect, customers and distribution floated on bulk
power system operations. As variable and bi-directional power flows increase there is a need to actively
manage de-stabilizing and harmful power quality effects. Integrating customer DER, distribution system
and markets into overall grid control schemes is needed. The foundation of control systems are:
observability, controllability and algorithms.
Grid 3.0 requires an ultra-large scale architectural solution based on a distributed control model with
federated controls across the bulk power system, distribution and customer tiers. Today’s centralized
control systems won’t scale to manage millions of distributed resources as they will become too
complicated, unwielding and unreliable. Distributed control contrasts with decentralized as the concept
is decentralized but with the additional property that multiple devices/algorithms cooperate with each
other on a common problem - overall grid control. Such multi-tier, distributed control architecture
allows each tier to “selfishly optimize” in coordination with the other tiers. This federated approach also
enables flexibility in terms of energy business models and encouraging innovation but preserves grid
stability and security.
Traditional grids are going to be the back-bone for a long time as Grid 3.0 is deployed at the pace of
value/need and so a transition plan is needed to blend new and old approaches without compromising
the essential integrity of our power system. This requires an investment plan to prioritize no regrets
decisions regarding long term investments in the distribution system, including less obvious assets like
14
L. von Prellwitz, Gridonomics, Cisco, 2011
15
J. Taft, Ultra-Large Scale Power System Control Architecture, Cisco 2012

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grid control management systems and communications infrastructure to supports this evolution and
that typically have 10-15 year asset lives, respectively.
Regulation & Policy considerations
Innovation & Technology Adoption
There is a tremendous amount of innovation that’s needed to develop the technologies and systems
associated with Grid 3.0 described above. The challenge is that the current level of regulatory
authorized funding for utility research and development is about 0.2% of revenues. Without utility
involvement, the technology development cycle significantly slows. In contrast, the UK regulator
recognized the critical role utilities play in applied research in collaboration with research institutions
and in new product development with technology suppliers. Ofgem targeted R&D spending at 0.5% of
utility revenues through its Innovation Funding Incentive (IFI) program for distribution utilities to meet
similar grid modernization goals.16
Aside from insufficient R&D funding, early stage technology failure risk is often too great for most
utilities to consider adopting for critical operations and later stage technology run the risk of failing to
“cross the chasm” from pilot to large scale deployment. There are two basic issues. One issue is related
to traditional regulatory rules in which utility shareholders bear a large burden risk of failed or
premature technology obsolescence. This asymmetric risk compounds the lack of R&D funding approval.
The second issue is that the industry and regulators would benefit from a more systematic approach to
technology development and adoption that links the R&D stage to field testing to large scale role out. In
this context, the opportunity to accelerate technology development and adoption would benefit greatly
from shared knowledge through joint research, development and demonstrations. EPRI’s expansion of
its traditional research programs into a collaborative framework for field demonstrations is very useful.
Perhaps there is an opportunity for state commissions to benefit from this information similar to how
utilities leverage for technology investment decisions. Such an exchange of information from
commission to commission could accelerate the knowledge transfer a pilot done in one service area or
one state or one region can be transferred to another without having to repeat or reinvent.
The time cycle for new technology products from research through system-wide deployment are long.
At first glance, many believe far too long – wrongly comparing the adoption cycle of consumer
electronics from the time they reach market to consumer purchase. Looking closer it becomes clearer
why the overall duration for technologies deployed at scale in the grid or grid operating systems may
take between 10-18 years. First, the time before a product is commercially ready for system-wide
deployment needs to be considered – mostly the time technology firms and institutions are researching
and developing new products. Also, the regulatory approval process through general rate cases or
separate proceedings can add 2 years or more. Deployment timelines a function of the technology to be
deployed, large operational software can take about 2 years while system-wide deployment of field
devices can take up to ten years depending on the number of devices and the complexity of the
replacement/installation. For example, system-wide deployment of 5 million meters in California took
16
Grid 2020: Toward a Policy of Renewable and Distributed Energy Resources, Caltech Resnick Institute, 2012

8
ten years from customer dynamic pricing research in 2003 through final meter installs in 2012. Below is
a conceptual timeline for electric industry product development and adoption. This timeline does not
reflect potential re-work loops if products don’t pass tests, business cases don’t pass regulatory review
or products fail or become prematurely obsolete during deployment.
Figure 4. Conceptual Technology Development & Adoption Timeline
Regulatory Decision Cycles
Regulatory decisions regarding investments for a future distribution system are significantly more
complex, involving multi-disciplinary experts within and outside a commission, and blurred Federal and
state jurisdictional boundaries. This is important as the regulatory decision process is on critical path –
given existing policies for DER the industry (technology firms, utilities & regulators) is behind schedule in
several jurisdictions. This was highlighted in a recent report by the Hoover Institution at Stanford
University17
;
“California’s energy system transformation depends upon an unprecedented level of innovation, in
technologies, grid systems, and new market entrants. Indeed, the very concept of the “smart grid” entails
advanced grid infrastructure, new control and energy management systems, and two-way
communication, as well as electric vehicles, microgrids, and energy storage. No such system yet exists,
and while some elements are in use or in development, going from scattered pilots to comprehensive use
in an electricity system for the 8th largest economy in the world that must remain reliable, secure, and
affordable, requires a massive integrated effort that cannot simply be mandated into existence.”
The complexity of the decisions is based on the range of factors driving the need for investment. Many
of these factors result from various DER related policies that are supported by different commissioners
and staff which can lead to siloed and slow decision making. There is a significant public benefit from
ensuring collection of a full range of evidence for multimillion dollar decisions, and hearing from all the
parties. However, at the current pace of change this model may become a bottleneck for advancement.
This can be further acerbated if commissions have separate dockets on energy efficiency, renewables
and another on demand response with each of these operating on its own timeline and its own
reasonable/benefits tests and cost recovery methods. An integrated approach will be necessary to have
a sensible rate regulatory structure for the scope and scale of electric system changes anticipated.
Fundamental to this approach will be the use of scenario planning and development of investment road
17
D. Grueneich, J. Carl, et al., Renewable and Distributed Power in California, Hoover Institution, Stanford
University, November 2012
YR1 YR2 YR3 YR4 YR5 YR6 YR7 YR8 YR9 YR10 YR11 YR12 YR13 YR14 YR15 YR16 YR17 YR18
Industry/Institutional Research
Vendor Product Development
Utility lab test & demonstration
Utility busn case development
Regulatory decision process
Utility system-wide deployment
(software 2yrs - field devices up to 10 yrs)

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maps that address advanced distribution systems and reliable integration of distributed energy
resources.
Distributed Markets
Another area to consider is the evolution of markets to enable the billions of transactions resulting from
Federal policy and regulation involving millions of customer resources. Several questions arise regarding
customer participation in markets at scale.
• How are the markets going to evolve?
• Who would participate in these markets?
• Who will run these markets?
• How will they be organized and governed?
• What is the role of state commissions and FERC?
As described earlier, there is a growing recognition in the industry among engineers and market
operators that the creation of a distribution level market for distributed energy resources may be
necessary as adoption reaches scale. For context, organized wholesale markets (e.g., Independent
System Operators) are primarily markets for deviations and reliability services. As such, less than 10% of
the energy in an ISO market is transacted in day-ahead or real-time market. Most energy is transacted
via bi-lateral contracts, such as Power Purchase Agreements. ISOs are also not designed to manage
transactions for millions of small resources, nor is it desirable from a control architecture perspective.
As the market adoption of distributed energy resources (DER) reaches regional scale it will create
significant issues in the management of the distribution system related to existing protection and
control systems. Therefore, it is important to consider the relationship between market design and grid
control systems as it relates to distributed energy resources to ensure market structures, power systems
and participation rules maintain a highly reliable system. If not addressed, this is likely to lead to issues
for customer power quality and reliability because of two issues resulting wholesale pricing models for
distributed resources that currently don’t reflect distribution level information related to location,
reliability or power quality considerations; (1) pricing schemes involving real-time spot market prices,
like Locational Marginal Pricing, are likely to create significant price volatility or operational oscillations
for customer resources that is not desirable and may be destructive; and (2) integrating distributed
resources into wholesale markets without aligning distribution control schemes may create
unacceptable instability and reliability consequences.18
Afterword
This paper is part of the Future of Distribution series and will be followed by a paper summarizing the
fourth EEI webinar discussion on regulatory policy related to DER related cost allocation, rate design and
utility business model implications.
18
P. De Martini, A. Wierman, S. Meyn and E. Bitar, Integrated Distributed Energy Resource Pricing and Control,
CIGRE Grid of the Future Symposium Proceedings, 2012

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