Toward a New Grid Operating Paradigm 2013

EEI Webinar 3 Paper draft

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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


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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


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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:

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EPRI staff, Needed: A Grid Operating System to Facilitate Grid Transformation, EPRI, 2011


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“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

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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

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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

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Grid 2020: Toward a Policy of Renewable and Distributed Energy Resources, Caltech Resnick Institute, 2012


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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

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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.

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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