More-Than-Smart-Report-by-GTLG-and-Caltech.pdf

THAN SMART

A Framework to Make

the Distribution Grid More Open,

Efficient and Resilient

ACKNOWLEDGEMENTS

This paper is based on the discussions at the first

two More Than Smart workshops as edited by Paul De

Martini of the Resnick Sustainability Institute at

the California Institute of Technology. The

More Than

Smart

initiative is managed by Tony Brunello of the Gree

ntech Leadership Group through the support of

the Energy Foundation. The 2

workshop was facilitated by John Danner of UC Berk

eley. For

information regarding the workshop participants, pl

ease visit the GTLG “More Than Smart” webpage at

www.greentechleadership.org

We wish to acknowledge the assistance provided by D

r. Neil Fromer, Prof. Steven Low, Dr. Lorenzo

Kristov, Genesis Rivas, and Andrew De Martini in th

e development of this paper and Heidi Rusina for

supporting the 2

workshop at the Resnick Institute. The content of

this report does not imply an

endorsement by any individuals or organizations tha

t participated in any More Than Smart workshop or

reflect the views, policies, or otherwise of the St

ate of California. It is intended to be a document

that

identifies and explores the future of California’s

electric distribution system so as to educate and

stimulate discussion among stakeholders regarding r

equirements for a distributed future.

GTLG is a 501(c)(3) nonprofit organization committe

d to providing policy leadership by connecting

innovators with policymakers. Participants in the o

rganization are leading companies, clean technology

business organizations and policy experts in the ar

eas of distribution grid innovation, energy data,

appliance energy efficiency, carbon management and

renewable energy. GTLG has been instrumental in

starting new initiatives including Mission Data (

www.missiondata.org

), Smart Electronics Initiative

(

www.howtokillavampire.org

) and other efforts found on the GTLG website.

Contents

ContentsContents

Contents

I. Executive Summary ..............................

...................................................

............................................. 3

II. Purpose .......................................

...................................................

.. 5

III. Integrated Grid Framework.....................

...................................................

......................................... 6

A. Distribution Planning ..........................

...................................................

.......................................... 7

Integrated Distribution Planning ..................

...................................................

................................. 8

Analysis Methodology & Tools ......................

...................................................

................................ 8

Operational & Distributed Energy Resource (DER) Mar

ket Data ..........................................

............. 9

DER/Energy Efficiency/Electric Vehicle Diffusion Sc

enarios ...........................................

................. 10

Multi-stakeholder engagement ......................

...................................................

............................. 10

B. Distribution System Design-Build ...............

...................................................

................................. 12

Grid as Open Network ..............................

...................................................

.................................. 12

Flexible Designs & Layered Architecture ...........

...................................................

.......................... 13

Deployment Timing Alignment........................

...................................................

............................ 14

Utility Grid Technology On-Ramp ...................

...................................................

............................. 15

C. Distribution System Operations .................

...................................................

................................. 16

Minimal Distribution Service Organization (DSO) Fun

ctions ............................................

............... 17

Reliability Coordination at Transmission-Distributi

on (T-D) Interface ................................

............. 18

Expanded DSO Roles ................................

...................................................

................................... 18

D. DER Integration into Operations ................

...................................................

................................. 19

Operational Grid Services .........................

...................................................

.................................. 20

Transparent Value Identification & Monetization ...

...................................................

..................... 21

Open Access Participation .........................

...................................................

.................................. 22

IV. Integrated Grid Roadmap .......................

...................................................

....................................... 24

Appendix A: Relevant California Policies ..........

...................................................

................................... 26

Appendix B: Assembly Bill 327 (Perea) Sec. 8 ......

...................................................

................................ 27

Appendix C: Value of the Grid .....................

...................................................

........................................ 28

References ........................................

...................................................

................................................. 3

I.I.

Executive Summary

Executive SummaryExecutive Summary

Executive Summary

California environmental and energy policies

combined with customer choices enabled by innovati

are forcing fundamental changes to California’s pow

er system. It is quickly evolving from the histori

cally

centralized structure toward a substantially more d

ecentralized future. This transition creates an

opportunity to significantly reduce greenhouse gase

s by harnessing the value of energy across the grid

from customers at the edge through the bulk power s

ystem. Essential to achieving this outcome is

enabling customer choice via an electric distributi

on system that becomes an open, integrated electric

network platform that is

more than smart

The current electric system serves the majority of

California well today. However, it is necessary to

consider the changes needed to scale to the levels

of distributed energy resources

(DER) envisioned in

California policy, including Assembly Bill 32

(Nunez) and Assembly Bill 327

(Perea). This is especially

true given the capital intensive nature of grid inv

estment and rapid distributed resource advancements

For example, changes are needed to integrate over 1

5 Gigawatts (GW)

of distributed resources into the

grid. As distribution infrastructure is largely de

preciated over several decades, investments this de

cade

may need to be useful to 2040. The implication for

California is that the current annual utility

distribution investment of nearly $6 billion

1,2,3

is effectively

a 25+ year bet on a future

– which will likely

be quite different than we can imagine today.

This paper is the result of a series of workshops w

ith industry, government and nonprofit leaders

focused on helping guide future utility investments

and planning for a new distributed generation

system. The distributed grid is the final stage in

the delivery of electric power linking electricity

sub-

stations to customers. To date, no state has initi

ated a comprehensive effort that includes the plann

ing,

design-build and operational requirements for large

scale integration of DER into state-wide distribut

generation systems. This paper provides a framewor

k and guiding principles for how to initiate such a

system and can be used to implement California law

AB 327 passed in 2013 requiring investor owned

utilities to submit a DER plan to the CPUC by July

2015 that identifies their optimal deployment

locations.

This paper outlines four key principles around dist

ribution grid planning, design build, operations an

integrating DER into operations to create a more op

en, efficient and resilient grid.

Distribution planning should start with a comprehen

sive, scenario driven, multi stakeholder

planning process that standardizes data and methodo

logies to address locational benefits and

costs of distributed resources

. Distribution planning is becoming more complex.

An integrated

planning and analysis framework is needed to proper

ly identify opportunities to maximize locational

benefits and minimize incremental costs of distribu

ted resources. This is enabled by a standardized

See Appendix A

Distributed energy resources means distributed ren

ewable generation resources, energy efficiency, ene

rgy

storage, electric vehicles, and demand response tec

hnologies

Global Warming Solutions Act of 2006, which set th

e 2020 greenhouse gas emissions reduction goal into

law

See Appendix B for AB 327 changes to Public Utilit

ies Code related to Section 769

15 GWs: 12 GWs of distributed generation, over 2 G

Ws of demand response, about 1 GW of energy storage

set of analytical models and techniques based on a

combination of utility grid operational data and

DER market development information to achieve repea

table and comparable results.

California’s distribution system planning, design a

nd investments should move towards an open,

flexible, and

node-friendly network system

(rather than a centralized, linear, closed one) th

enables seamless DER integration.

California’s vision for significant DER contribu

tion to resource

adequacy and safe, reliable operation of the grid r

equires a move to a network system. The

evolution to an open platform will involve foundati

onal investments in information, communication

and operational systems not seen in existing utilit

y smart grid plans. These investments should be

based on solid architectural grid principles while

ensuring the timing and pace align with customer

needs and policy objectives. In the future, the st

ate should strive toward converging electric utilit

designs with other distribution systems for gas, wa

ter and other services.

California’s electric distribution service operator

s (DSO) should have an expanded role in utility

distribution operations (with CAISO) and should act

as a technology-neutral marketplace

coordinator and situational awareness and operation

al information exchange facilitator while

avoiding any operational conflicts of interest.

Today, bulk power systems and distribution system

are largely operated independently. DSO’s can help

play an integrating role with CAISO. California i

already at the point at which integrated and coordi

nated operations based on better situational

information is essential. This integration requires

both an expansion of the minimal functions of

utility distribution operations and clear delineati

on of roles and responsibilities between the CAISO

and utility distribution system operators. Finally,

as with transmission, distribution operations will

need standards of conduct to ensure neutral operati

onal coordination.

Flexible DER can provide value today to optimize ma

rkets, grid operations and investments.

California should expedite DER participation in who

lesale markets and resource adequacy,

unbundle distribution grid operations services, cre

ate a transparent process to monetize DER

services and reduce unnecessary barriers for DER in

tegration.

Flexible DER can provide a wide

range of value across the bulk power and distributi

on systems. The issue is not

when

, but

rather

how

do we enable integration of flexible DER into thes

e systems. This will be enabled by the

expansion of CAISO services and new distribution op

erational services. As such, new capabilities

and performance criteria should be identified as pa

rt of the distribution planning process. These

new services should be coordinated with existing pr

ograms knowing some existing demand

response programs may be surpassed in their relevan

ce and value in the context of AB 327

objectives. Finally, barriers to broad participatio

n involving complex and expensive measurement

and verification schemes and related settlement pro

cesses should be simplified for DER.

The distribution plans that each of the California

IOUs will need to file to comply with AB 327 repres

ent

the first step towards starting to re-shape the dis

tribution grid. The role of this paper is to provid

e a set

of strategic frameworks and guiding principles that

can inform stakeholders and policymakers in the

development of AB 327 Distribution Plans that the C

PUC will eventually ratify. Additionally, as other

states and international locales consider a more di

stributed electric system this paper offers guidanc

on the critical questions and a framework for devel

oping the path forward for their particular

distribution systems.

II.

II. II.

II. Purpose

PurposePurpose

Purpose

California environmental and energy policies

combined with customer choices enabled by innovati

are forcing fundamental changes to California’s pow

er system. It is quickly evolving from the histori

cally

centralized structure toward a substantially more d

ecentralized future. This transition creates an

opportunity to significantly reduce greenhouse gase

s by harnessing the value of energy across the grid

from customers at the edge through the bulk power s

ystem. Essential to achieving this outcome is

enabling customer choice via an electric distributi

on system that becomes more transparent in terms of

information and open in terms of access. This paper

focuses on the optimal integration of distributed

energy resources into the electric system and the r

elated evolution of the existing distribution syste

m to

become an enabling network to realize the benefits

for ratepayers and users of the system.

While the current electric system serves the majori

ty of California well today, it is necessary to con

sider

the changes needed to scale to the levels of DER en

visioned in California policy, including AB 32

and AB

327

. This is especially true given the capital intens

ive nature of grid investment and rapid distributed

resource advancements. For example, changes are nee

ded to integrate over 15 GWs

of distributed

resources into distribution and/or bulk power syste

m operations. This amount of DER may be low as

technological innovation is accelerating.

Bill Gates observed, "We always overestimate the

change that

will occur in the next two years and underestimate

the change that will occur in the next ten." As

distribution infrastructure is largely depreciated

over several decades, investments this decade may

need to be useful to 2040. The implication for Cali

fornia is that the current annual utility distribut

ion

investment of nearly $6 billion

5,6,7

is effectively

a 25+ year bet on a future

– which will likely be quite

different than we can imagine today.

This paper continues a conversation among a diverse

set of experts about the future of California’s

power system with a particular focus on its role an

d desired attributes. The objective is to define an

integrated grid framework and related guiding princ

iples that link California’s policy goals and desir

integrated power system qualities to utility implem

entation practices. Specifically, those practices

related to distribution

planning, design-build, operations

and the

integration of DER

into markets and

grid operations. This paper is derived from the dis

cussions in a 1

More Than Smart Workshop in

September 2013 and a 2

workshop at Caltech’s Resnick Sustainability Insti

tute in June 2014. This

paper will serve as a primer for a 3

workshop planned for fall 2014 and a source of ind

ustry insights for

relevant regulatory activity in California and else

where.

See Appendix A

Global Warming Solutions Act of 2006, which set th

e 2020 greenhouse gas emissions reduction goal into

law

See Appendix B for AB 327 changes to Public Utilit

ies Code related to Section 769

15 GWs: 12 GWs of distributed generation, over 2 G

Ws of demand response, about 1 GW of energy storage

. .

. Integrated Grid Framework

Integrated Grid FrameworkIntegrated Grid Framework

Integrated Grid Framework

The electricity system has been called the most com

plex machine developed by humans. This complex

system has many interdependent components that must

work harmoniously to ensure safe and reliable

service. Any material changes to the system need to

be considered holistically. This is why a systems

view is essential to evaluate the transition underw

ay for the electric grid in California, Hawaii

, New

York

and other places around the world.

The integrated grid framework in figure 1 below pro

vides a systems view to conceptually illustrate the

linkage between California’s existing policy goals

and regulatory defined electric system qualities we

want to achieve, and the lifecycle development proc

esses used to implement those goals and qualities

in practice. This framework was developed from the

comments and discussion in the first More Than

Smart workshop utilizing a systems engineering appr

oach. A systems engineering approach involves

holistic design and management of complex engineeri

ng projects over their integrated life cycles. The

process starts with identifying the policy objectiv

es as well as customer needs to define system quali

ties

and by extension the system design along with opera

tional requirements.

Figure 1: Integrated Grid Framework

This integrated lifecycle is identified above as th

e Distributed System Lifecycle shaded in dark green

. The

four key stages are:

(1) Distribution Planning, (2) Distribution Design-

Build, (3) System Operations

and

(4) DER Integration into Operations

. Each interdependent stage represents a set of par

ticipants

(people), complex processes and technologies. In t

his paper, a set of guiding principles is identifie

d for

each stage to enable customer needs and policy outc

omes. Further definition of the attributes and

requirements for each stage will lead to repeatable

and scalable methods that address immediate and

future system needs. This paper is purposely agnost

ic regarding technical solutions and technology.

The focus of this paper is not to define “what we w

ant to achieve” as this has been clearly identified

and

codified in California law, regulation and standard

s. The focus is instead on the, “How are we going

execute on this vision?” considerations. This, in p

art, requires creating lines of sight between the p

olicy

goals and tactical implementation. It is also requ

ires alignment of all aspects of the framework to

accomplish the desired results. These various aspec

ts should be viewed as synergistic, not additive if

the

objectives of AB 327 are to be achieved. This is wh

y it is essential that a holistic, systematic appro

ach is

used.

Implementation will involve substantial changes to

the processes and methods used in each of the

lifecycle stages. AB 327 specifically calls for sp

ecific changes as noted in the discussion below. B

ut, this

law is only one of several existing California poli

cies that should be considered for planning, design

-build

and operation of the distribution system going forw

ard. As such, there are several proposed guiding

principles for each stage to address the holistic c

hanges needed. These are drawn from the More Than

Smart workshops and best practice defined in severa

l industry papers, such as EPRI’s The Integrated

Grid

, Environmental Defense Funds Smart Grid Scorecard

, DOE’s Modern Grid Initiative

, Carnegie

Mellon’s Smart Grid Maturity Model

, and Gridwise Architecture Council’s Decision Make

r Checklist

If done well the revised process for each stage wil

l result in defining a set of integrated requiremen

ts for

development of an electric system to meet Californi

a’s needs for today and well into the 21

century.

ISTRIBUTION

LANNING

Ensure ratepayers realize the net benefits from the

optimal use of distributed resources at minimal

cost to integrate these resources into the electric

system.

California law AB 327

requires investor owned utilities to submit a dist

ributed resource

plan proposal

to the CPUC by July 1, 2015 that identifies optimal

locations for the deployment of distributed resour

ces.

Also, that the “evaluation shall be based on reduct

ions or increases in local generation capacity need

avoided or increased investments in distribution in

frastructure, safety benefits, reliability benefits

, and

any other savings the distributed resources provide

s to the electric grid or costs to ratepayers of th

electrical corporation.” Subsequently, any addition

al distribution investment plans will need to consi

der

maximizing the locational benefits and minimizing t

he incremental costs of distributed resources. Thi

analysis must also consider “safety standards relat

ed to technology or operation of the distribution

circuit in a manner that ensures reliable service.”

This last criteria is also part of the Operationa

l Risk

requirements for California investor-owned utilitie

This level of planning now required in California i

nvolves a wider and more complex range of

engineering and economic issues in an integrated an

d multi-disciplinary fashion with direct participat

ion

of relevant stakeholders. This includes:

•

An integrated planning and analysis framework to pr

operly identify the criteria, issues,

interdependencies and methods of analysis

•

Standardized set of related analytical models and t

echniques to achieve comparable results

Distributed Resources as defined by AB 327 means,

renewable distributed generation, energy storage, p

lug-in

electric vehicles

•

Qualified access to utility operational and competi

tive market data to facilitate stakeholder

analysis and independent research

•

Use of future scenarios related to varying amounts

and timing of DER and electric vehicle

adoption to stress test distribution investment pla

ns and DER benefit-costs

•

Transparent processes incorporating relevant stakeh

older participation

Integrated Distribution Planning

The first step toward an integrated systematic appr

oach is development of a standardized planning

framework. This is because of the diversity and sca

le of California’s current DER objectives. This

planning framework would involve identifying custom

er needs and uses of the distribution system,

along with DER diffusion modeling, integrated resou

rce planning, power system engineering and

economic analyses needed along with the interdepend

encies among each. The opportunity exists to

achieve California’s objectives if we holistically

understand the interrelationships and related benef

its

and costs of DER and the grid. Currently, such an i

ntegrated framework does not yet exist

and therefore

many analyses performed today may be significantly

deficient in answering the long-term questions

raised in statues.

Framing the planning objectives in a practical and

standard manner is essential to yield comparable

results across the state. For example, the followin

g three objectives should be clearly defined prior

the utility distribution planning required under AB

327:

•

“Locational benefits”

•

“Optimal location”

•

“Value optimization”

Discussion in the 2

workshop highlighted that “value optimization” cou

ld be construed as value

maximization or cost minimization. Cost minimizati

on in this case is the integrated lifecycle costs

related to the environment, electric system value c

hain, society and customers. Also, it is important

define local optimization and benefits in the conte

xt of the whole system. The parameters for any

planning objectives need to be identified. This sho

uld include identifying inputs such as flexibility,

reliability, and resiliency as well as the scope of

analysis. These parameters should also address ho

w to

consider customer value or externalities. The effe

ctive limits of an analysis should be defined.

California utilities continue to make significant i

nvestment in grid modernization. PG&E, for example,

has incorporated fundamental changes to enable inte

gration of DER at scale. These changes include

larger distribution wire sizes and transformers tha

t also improve safety and reliability. Given these

grid

modernization investments, distribution planning sh

ould start by establishing a common understanding

of the capabilities of the existing system as a “ba

seline”. This baseline evaluation should be stress

tested for any capability gaps by a set of potentia

l future scenarios described below.

Analysis Methodology & Tools

Existing distribution planning process, methods and

modeling tools aren't equipped to fully assess the

increasing random variability of supply and demand

resources.

17,18

Historically, variability of net

customer demand was rather predictable based on wea

ther and macroeconomic factors. Plus, few

distributed generators were directly interconnected

to low voltage distribution systems so the impact

EPRI is currently developing such a framework as p

art of the Integrated Grid program.

the system was negligible. This has changed based

on the scale and pace of DER adoption and

California’s goals. Analysis today requires both th

e traditional power engineering analysis as well as

assessment of the random variability and power flow

s across a distribution system. Such an analysis

would include real and reactive power flows under a

variety of planned and unplanned situations across

a distribution system, not just a single feeder. E

volution to a more network centric model for a

distribution system to enable bi-directional power

flow underscores the need for a fundamental shift i

planning analyses.

As such, a more sophisticated and proactive

approach is needed to consider the “optimal locati

ons”

for DER. Value assessment as defined in AB 327 requ

ires an evaluation of “locational benefits and cost

of distributed resources located on the distributio

n system.” As noted before, these analyses require

complex set of interrelated models to conduct.

Also, a more dynamic interface with the transmiss

ion

system may occur and so analysis of the T-D interac

tion is necessary. A 2013 CEC commissioned study

identified the “

need for studies and tools that capture the detail

of distribution and distribution‐

connected generation with transmission for a unifie

d regional view” (pg. 3).

Additionally, many of these analyses will involve t

rade-offs. One is the trade-off between economic

optimization and system robustness (resilience & re

liability). The challenge for distribution plannin

unlike transmission, is that there is no current an

alytical framework to address the inherent trade-of

between economic optimization and operational robus

tness. Failure to address this significant gap is a

recipe for potentially disastrous results before 20

30. Taking this a step further, there are optimizat

ion

trade-offs between environmental, societal, grid-ba

sed and customer-based solutions. It is also

important to recognize that the power system is bec

oming considerably more complex. This can create a

more fragile system, not more resilient, if not don

e properly. There is a need to understand the

inherent trade-off related to simplicity versus com

plexity in planning. This is best done through anal

ysis

of an expanded set of operational risks

22,23

not identified in the current CPUC Operational Ris

proceeding. The planning framework must be able to

address these types of trade-offs.

Based on the various new and converged analyses des

cribed above, there is a need to identify existing

tools that can be used and any gaps that exist. A p

rioritization of the analyses is urgently needed as

time

is short to support AB 327 requirements, energy sto

rage procurements, smart grid and operational risk

plans.

Operational & DER Market Data

To enable research and transparency with the analys

es, qualified access to grid asset and operational

data is needed. Similarly, competitive DER/EE marke

t data from services firms is required. This

foundational data should be accessible, visible, an

d available (in terms of time granularity and type

data). Such access could be provided consistent wi

th existing confidentiality rules for transmission

planning and other utility operational data. Also,

NERC’s synchrophasor data repository may offer

guidance on allowing limited access for research an

d transparency while respecting legitimate security

and confidentiality concerns. Conversely, utility p

lanning and analysis would benefit from confidentia

information provided by DER developers and services

firms regarding system performance

characteristics, market information and plans in th

eir planning areas. There may also be an opportunit

to consider expanding the role of the CPUC’s new En

ergy Data Center

to also include this operational

and market planning data.

DER/EE/EV Diffusion Scenarios

A key challenge for determining value as well as th

e timing and magnitude of grid investment is the

uncertainty related to the diffusion patterns for D

ER, energy efficiency, electric vehicles, microgrid

s and

zero net energy code compliance. A set of future sc

enarios looking toward 2030 and beyond are useful

to guide discussion of the evolution of California’

s electric system to support customer’s choices and

public policy. There is a recognition that Californ

ia is at a crossroads with respect to the future ro

le of

the electric system generally and the distribution

system specifically. The discussion at the 2nd Mor

Than Smart workshop identified the value of scenari

os, as possible futures for distributed energy

resource deployment, electric vehicle adoption and

customer participation. These scenarios would be

used to ‘stress test’ existing utility distribution

systems, planned investments and research and

development activity (in general rate cases, EPIC p

rograms, and smart grid roadmaps).

Ideally, utilities would develop at least three fut

ure scenarios for the purpose of stress testing the

baseline capabilities of the distribution system. S

cenarios when used in conjunction with long term

distribution infrastructure capital planning, shoul

d cover at least a 20 year time horizon. These

scenarios should incorporate a range of relevant pa

rameters including diffusion of various types of DE

(plus EVs and energy efficiency), socioeconomic fac

tors, and other key aspects. These scenarios shoul

incorporate assumptions related to state policy goa

ls (e.g., 12,000 MWs of local DG, 1.5 million ZEVs,

of peak met by DR). These assumptions could be aug

mented by insights from stakeholders and research

analysis by Lawrence Berkeley National Lab (LBNL) a

long with other research organizations as well as

scenarios developed in related California proceedin

gs and planning. In these scenarios, DERs must be

assumed to provide services identified in utility D

istribution Resource Plans. In conjunction with th

scenarios, the specified system qualities below can

be used to test the robustness of distribution pla

ns.

The characteristics for each of the integrated syst

em qualities below would be outlined based on each

stakeholder (e.g., Customer, DER provider, DSO and

TSO) specified needs.

Figure 2: Integrated System Qualities

Multi-stakeholder engagement

The number of vested stakeholders in the distributi

on planning process has greatly expanded and

incorporating stakeholder (including representative

s of customers) engagement and input as well as

greater transparency to the process is needed. Ther

e is also a concern that California’s plethora of

incentives, programs and policies for different cle

an technologies and resource types are not well

coordinated, leading to inefficiencies in planning.

It is also critical that the opportunity/problem t

o be

solved needs to be defined from an integrated syste

m view and not from a single stakeholder or

technical solution perspective. These consideration

s suggest the need for revised processes to create

multi-stakeholder, scenario driven planning process

similar in concept to that developed for

transmission by CAISO in 2010.

However, engaging more stakeholders in such a plann

ing process may increase the time for outcomes.

Balancing the need for multi-stakeholder involvemen

t with the need for accelerated changes to the

distribution system will be a critical challenge th

at should be considered. Such as the need to identi

and be in the position to execute short term reliab

ility system upgrades versus longer term reliabilit

investments required to support DER. One area that

appears ripe for stakeholder engagement is the

identification of optimal locations guided by plann

ing and asset data in support of realized benefits.

Recommended Reading

Reference paper for analogous approach to scenario

based planning:

CAISO Transmission Planning

Process,

2010

Guiding Principles for Distribution Planning

Based on the workshop discussions, the following gu

iding principles and potential requirements are

offered for consideration. These are aligned with r

elevant federal and state policies, and leverage

industry research and best practices referenced in

this paper.

ISTRIBUTION

YSTEM

ESIGN

-B

UILD

Develop robust open, node-friendly electric network

designs that address safety and reliability needs

while incorporating architectural elements that ena

ble innovation across the electric system and

enhance customer value from connectivity.

Distribution system designs, investment decisions a

nd related technology adoption processes for

physical infrastructure, protection and control sys

tems and operational systems need to quickly evolve

toward achieving the objectives below in a cost eff

ective manner and mindful of customer rate impacts:

•

Grid as open network model to enable seamless DER/m

icrogrid integration

•

Employ flexible designs and layered architecture to

create flexibility while managing complexity

•

Align timing of infrastructure/systems deployment w

ith needs

•

Well defined and functioning utility advanced techn

ology on-ramp

Distribution designs today generally reflect a trad

itional set of assumptions and uses for distributio

circuit. Standard engineering design practices are

often based on 50 year old operating paradigms. Thi

may lead to significant stranded investment risk be

ginning in the next decade. It is essential that

distribution designs align to the new requirements

driven by customer choices and public policy.

This alignment also raises questions about the futu

re role and value of the distribution system given

potential growth of customer self-sufficiency

or independent micro-grids. In this context, the

discussion at the 2

MTS workshop identified a “node-friendly”

network model as the desired among

four potential distribution end-states. The four en

d-states are; Grid as Back-up, Current Path, Grid a

Network, and Convergence.

These end states should be viewed as on a continuu

m in terms of the

value of the grid. In this context, Grid as Back-u

p envisions the grid providing less value than in t

other end-states. The Current Path is analogous to

the “baseline” discussed earlier. In the Convergenc

role the electric system provides the highest value

. The discussion in the workshop recognized the val

of an advanced grid and focused on Grid as Network

with aspirations for evolving to a convergence end-

state.

These end-states could be used to assess system qua

lities and validate whether utility investment plan

derived from the scenario analysis and planning ali

gn with a particular desired end-state.

Grid as Open Network

An open network end-state builds on the current inv

estments through an acceleration of more

advanced technology adoption into the grid along wi

th an evolution of distribution system designs to

A node is a distribution grid interface with custo

mer or merchant DER or microgrid

See Appendix C for expanded definitions

create a node-friendly network. This network platfo

rm can incorporate seamless integration of DER and

independent microgrids. This network platform model

envisions a proactive approach to manage the

alignment of investment to enable the adoption of D

ER. Such decisions would be made strategically

through a collaborative assessment of optimal inves

tment. This open electric network platform and

related operations enables upwards of 20 GWs of dis

tributed energy resources and over 1.5 million

electric vehicles to integrate safely and reliably

while also contributing to the reduction of greenho

use

gases.

Fundamentally, these distribution designs need to c

onsider how to evolve a closed single purpose

system to a more open, flexible, operationally visi

ble and resilient platform that can accommodate

anticipated DER integration and future innovations.

Such a platform would involve “node-friendly”

standardized, low cost physical and information int

erconnections.

This would enable interconnection

without lengthy studies. This approach would also a

llow for the continued evolution into a multi-cellu

lar

structure comprised of microgrids as discussed in t

he recent CPUC staff microgrid report

. This will not

be easy or simple, yet engineering solutions enable

d by technology innovations must be developed.

To accomplish this, distribution designs will likel

y evolve to a level beyond that contemplated in mos

smart grid plans. This “More than Smart” level is w

hat EPRI describes as The Integrated Grid.

Evolution

may require rethinking of circuit designs to other

configurations, like the loop designs currently bei

tested in several utility demonstration programs, i

ncluding SCE’s Irvine Smart Grid Demonstration

project

and utility microgrids such as SDG&E’s Borrego Spr

ings project

The 2

MTS workshop discussion centered on evolving distr

ibution to achieve the network platform

attributes and associated integrated value as refle

cted in this paper. However, the discussion identif

ied

the need to more fully explore, as in New York

, the potential to enable innovation across the pow

system and other critical infrastructure such as wa

ter and transportation. Conceptually there is a re

potential for “network effects”

through the synergistic value that could be create

d from such a

convergence. This is a stretch goal, but worth con

sideration as part of any More Than Smart design.

Flexible Designs & Layered Architecture

The incorporation of advanced digital technologies

and DER into the operation of the electric system

requires consideration of the information, communic

ation and physical interface considerations. For

example, networked distribution systems will necess

arily involve technologies with different lifecycle

s as

more digital and software components are added. Als

o, interfaces with customers and 3rd party systems

will likely be more dynamic as these systems will h

ave different lifecycles. These cyber-physical

interfaces become critical to achieving an open and

flexible network desired. Therefore, it is essenti

that a systems engineering approach leveraging inte

roperability principles

is employed to integrate

fast and slow cycle technologies. By understanding

the functional requirements and interfaces it is

possible to define boundaries to create a flexible

system. Modularity would mitigate stranded cost ris

and enable future optionality to benefit from unfor

eseen innovations such as was the case with modular

smart meter designs developed before the iPhone was

launched. The key to modularity is defining the

boundaries correctly. This is fairly complex and in

volves identifying those engineering-design

“constraints that de-constrain”

. If done well, constraining aspects of the design

will allow flexibility

around the constrained aspect. This modular and lay

ered approach is what enables the internet to

foster innovation in applications as well as hardwa

re.

A number of architectural issues need to be address

ed as distribution increasingly evolves from human-

centric passive/reactive management to highly autom

ated active management.

As such, operational

systems will also evolve in complexity and scale ov

er time as the “richness” of systems functionality

increases and the reach extends to greater numbers

of intelligent devices at the edge of the system. T

his

also introduces operational risks from increases in

system complexity and the cyber-attack surface.

This increased complexity requires new ultra large-

scale layered architectural approaches

to manage

data and interfaces across thousands and potentiall

y millions of end points, federated controls to

manage various latency requirements for certain gri

d operations, system security, reliability and

extensibility. These systems will be based on archi

tecture that embeds digital processing and analytic

s as

well as control software at many locations in and a

long the power grid infrastructure to implement

flexible grid automation.

Deployment Timing Alignment

The current efforts of California’s utilities

39,40

to modernize the grid has been widely recognized a

among the world’s leading efforts. But, the pace a

nd scope of change incorporated into the multi-bill

ion

dollar distribution investment plans may not be suf

ficient to meet customer needs and policy objective

This is due in part to the lag between accelerated

customer DER adoption, and increasing policy

mandates compared to the cycle time for engineering

, design and construction. These alignment issues

can be addressed by basing investment decisions on

scenario based planning. Additionally, timing risk

can be mitigated by identifying those investments t

hat are required under any future scenario. These

“no regrets” investments include advanced field tel

ecommunications networks and increasing grid

operational visibility – to allow more operational

data, moving freely, in real time. This effort can

accelerated by focusing initial efforts within the

development of optimal or preferred locations, revi

sing

in-flight programs such as fault indicator, switch

automation, and capacitor control programs to offse

otherwise expenditures that would become obsolete.

Also, many of these developments will need to be

concurrently consistent across roadmap work streams

However, reducing the deployment time cycle for new

designs and related technology solutions is

critical. System-wide deployments take a long time

from design to full deployment. At first glance, ma

believe far too long – wrongly comparing the adopti

on cycle of consumer electronics from the time they

reach market to consumer purchase. Looking closer i

t becomes clearer why the overall duration for

technologies deployed at scale in the grid or grid

operating systems may take 10 years or more. Below

a conceptual timeline example for electric industry

product development and adoption. There are limits

to accelerating field deployments given safety cons

iderations and availability of qualified people and

equipment. But, there are opportunities to consider

accelerating the front end of the lifecycle involv

ing

research, development and demonstration and busines

s and regulatory decision making.

Introduced by Caltech Prof. J. Doyle and discussed

in Prof. S. Low’s blog

https://rigorandrelevance.wordpress.com/2013/11/26/

power-network-and-internet-i-architecture/

Figure 3: Operational Technology & Field Infrastruc

ture Lifecycle

Utility Grid Technology On-Ramp

Technology advancements in the information and ener

gy technologies that enable a modern grid are

available or within reach. As recognized by the cre

ation of the EPIC research and development funding

and Smart Grid Roadmaps, utilities play a critical

role both in new product development with technolog

suppliers and collaboration with research universit

ies, institutes and national labs. Without utility

involvement the technology development cycle signif

icantly slows. But, the adoption process doesn’t

stop with lab testing or pilots. It is essential f

or California that well defined technology adoption

on-

ramps into operational deployment are established f

or grid infrastructure and operational systems

technology. This would include lessons learned and

shared information about technology testing and

pilots. Likewise, it is important that scale pilots

to demonstrate operational readiness of a wide ran

ge of

flexible distributed resources (e.g., dispatchable

generation, energy storage, electric vehicles and

customer load) are conducted soon.

Such on-ramps for advanced grid technology and DER

participation would align EPIC research and

development funding with integrated resource and pr

ocurement plans, Smart Grid Roadmaps and

general rate case funding requests for capital inve

stment. Of course, technology development should

align with public policy and customer benefits. The

reby, customer benefits and policy values pulling

through new technology. This type of alignment is l

argely done in the energy efficiency and demand

response area and was a critical part of the smart

meter development and deployments. The time is

now to address advanced grid technology adoption to

enable the open network model. As such, the

distribution plans envisioned in AB 327 should iden

tify specific actions and incremental investment

needed to develop an open, flexible electric distri

bution network as well as the related operational

platform.

Recommended Reading

Reference papers for deeper discussion:

•

The Integrated Grid

, EPRI, 2014

•

Future of Distribution

, EEI, 2012

Guiding Principles for Distribution System Design B

uild

Based on the workshop discussions, the following gu

iding principles are offered for consideration. The

are aligned with relevant federal and state policie

s, and leverage industry research and best practice

referenced in this paper.

YSTEM

PERATIONS

To provide safe and reliable electric service acros

s distribution system and operational boundaries

while enabling seamless integration of DER and micr

ogrids into markets and grid operations.

Providing safe and reliable electric service in a m

ore distributed system requires an integrated and

coordinated operational paradigm. This paradigm sho

uld clearly delineate roles and responsibilities

between California Balancing Authorities (BA) like

the CAISO, other transmission system operators and

utility distribution system operators (DSO). These

responsibilities include:

•

Minimal DSO functions to ensure safe and reliable o

perations

•

Reliability coordination at Transmission to Distrib

ution (T-D) interface

•

Potentially expanded DSO roles as energy transactio

ns across distribution grow

The fundamental role and responsibility of the BA r

emains to provide reliable open-access transmission

service. This entails maintaining supply-demand bal

ance and transmission reliability through the

scheduling and dispatch of resources and interchang

e transactions with other regional balancing

authorities. The new challenge for the BA arises fr

om the need to consider the increasingly dynamic ne

load and high penetration of flexible DER across th

e T-D interface at a substation or locational margi

nal

pricing node (P-node). This drives the need to reco

nsider the various roles needed for physical operat

ion

and those for market operation need in the context

of scaling DER to over 25% of California’s peak

demand. This brings about the question as to how ap

propriately balance existing California policy with

economic impacts to customers when considering RPS

goals that apply to both transmission and

distribution.

Figure 4: Integrated Electric System Operations

Minimal DSO Functions

The discussion of the potential role of distributio

n utilities often confuses the two distinct functio

ns;

physical operation of the electric system and that

of market operation. These functions are closely

related, but different. The following discussion is

focused on the physical coordination of real and

reactive power flows across the distribution system

in an integrated manner with the CAISO. In this

context, there is a new set of minimal functional r

esponsibilities that define the new DSO. These new

functions are in addition to the traditional DSO op

erational functions, like outage restoration and

switching for maintenance. One function is managing

distributed reliability services involving many

types of DER and independent micro-grids providing

distributed reliability services

to support

distribution system operations

The ability of the DSO to utilize locally-provide

d reliability services will

also enable the DSO to maintain more stable and pre

dictable interchange with the BA at the T-D

interface. The minimal DSO functions also include r

esponsibility to BA for providing situational

awareness involving forecasting, real-time measurem

ent and reconciliation of net load, dispatchable

DER resource, and real and reactive power flows fro

m the distribution side of a P-node.

It is important to clarify that the DSO functions d

escribed here do not require the DSO to be inserted

into wholesale market operations and related econom

ic transactions between parties involving DER.

Rather, the core operational safety and reliability

based DSO activities confine the DSO to managing r

eal

and reactive power flows across the distribution sy

stem. These activities require tight integration of

the

people, processes and technology used to operate th

e distribution system. Any concerns about conflict

of interest regarding the coordination of energy an

d capacity delivery schedules, can be addressed

through the use of standards of conduct (SOC) model

ed after the successful Federal Energy Regulatory

Commission’s transmission operation SOC

adhered to by utilities for over 15 years.

Reliability Coordination at T-D Interface

Another function required of the DSO is T-D interfa

ce reliability coordination

This function is to ensure

that services provided by DER are properly coordina

ted, scheduled and managed in real-time so that the

BA has predictability and assurance that DER commit

ted to provide transmission services will actually

deliver those services across the distribution syst

em to the T-D interface.

This coordination also

involves ensuring that DER dispatch (via direct con

trol or economic signal) doesn’t create detrimental

effects on the local distribution system, and will

require coordination of physical power flows at the

T-D

interface between the BA and DSO.

The need for

real and reactive power flow coordination across di

stribution and the T-D interface is likely

to increase with the growth of DER and related exce

ss energy available for resale. This involves more

than forecasting and managing net load as identifie

d in the CAISO Duck Curve analysis.

It is also very

likely that energy transactions may occur within an

y given local distribution area between distributed

generators and municipal utilities, power marketers

and energy retailers. At a minimum the physical

aspects (not the financial aspects) of these transa

ctions will need to be coordinated as part of the D

SO’s

function of reliable distribution system operation.

This does not mean that DSOs will operate balanci

markets or an optimal resource dispatch function as

done by the BA at the wholesale level. Supply-

demand balancing will remain the sole responsibilit

y of the BA. The DSO will, however, need to

coordinate energy delivery schedules to ensure oper

ational integrity of the distribution system.

Expanded DSO Roles

There is a set of potential market facilitation ser

vices beyond the minimum that may be provided by a

utility DSO and/or third parties. An example is an

evolution of the schedule coordinator role as

described in CPUC Rule 24. If desired, the rule ma

y need to be changed to allow investor owned utilit

ies

to offer this service. Also, incorporation of ener

gy storage into the distribution system may enable

DSOs

to offer new non-core market enabling services simi

lar to those provided by natural gas distribution

utilities. Such services may include “park and loan

,” where parties may park or store energy that cann

be delivered immediately to be scheduled for delive

ry at another time. Likewise, DSOs may sell or loa

short-term real or reactive power as needed to make

-up for deficiencies in scheduled deliveries. The

gas operational concept of “line pack” to increase

the amount of energy that may be delivered in a sho

period may also be adapted to electric distribution

systems with certain energy storage and demand

management technology.

Recommended Reading

Reference paper for deeper discussion:

Century Integrated System Operations

, Caltech-CAISO, 2014

Guiding Principles for System Operations

Based on the workshop discussions, the following gu

iding principles are offered for consideration. The

are aligned with relevant federal and state policie

s, and leverage industry research and best practice

referenced in this paper.

DER

NTEGRATION INTO

PERATIONS

Create opportunities for qualified DER to contribut

e to the optimization and operation of markets and

the grid, and reduce the barriers and costs to part

icipate.

Flexible DER can provide value to optimizing market

s and grid operations, and infrastructure

investment. This was identified and defined in rese

arch by Sandia National Labs

and SCE

and now

required by AB 327. So the issue isn’t

when

, but rather

how

do we enable integration of flexible DER

into bulk power and distribution systems. There are

several steps needed to needed to consider how to

a) allow DER to fully participate in CAISO markets,

b) allow DER to mitigate incremental interconnecti

costs, c) allow DER to meet distribution reliabilit

y and power quality services, and d) enable DER to

provide an alternative for certain distribution inv

estment. Additionally, there are several market

barriers to DER participation as summarized by LBNL

Therefore, to achieve California’s policy

objectives there are four key aspects that need to

be addressed:

•

Fully address DER potential to participate in bulk

power system (e.g. wholesale energy and

ancillary service markets) and to meet near, mid an

d long term resource adequacy requirements

•

Unbundle and define distribution operational grid s

ervices

•

Create transparency related to the value of service

s and related monetization methods (e.g.,

market, bi-lateral, tariff, etc.)

•

Development of more open access rules and processes

(incl. participant qualifications

connectivity and measurement requirements, and sett

lement)

Operational Grid Services

Flexible DER is expected to provide a wide range of

value across the bulk power and distribution

systems. This will be enabled by the expansion of C

AISO services and new distribution operational

services. Bulk power system services may include: l

oad following (ramp up/down), resource adequacy,

reactive power support, and system inertia response

Distribution level services may include:

voltage/reactive power

, power quality, power flow control and reliability

services

. This needs to be

done on a technology neutral basis. The starting po

int for such an effort has been developed by Sandia

and SCE in their respective storage analysis report

s, but it is important to note that their analysis

applies

to any flexible DER technology that can meet one or

more of the over 20 services identified below in

figure 6. There is an immediate need to prioritize

those new bulk power and/or distribution services

needed over the next 1-3 years in California to beg

in the development process.

Figure 5: Potential Operational and Economic Servic

Fully realizing the value of DER for the bulk power

and distribution systems requires assurance of

performance to avoid the need for new dispatchable

generation and/or physical infrastructure to

manage the operations of the electric system. As su

ch, it is essential that clear performance

requirements are specified for each service. This i

s because the evolving system operations discussed

this paper requires firm, dependable resources that

can respond in kind to dynamic operational

conditions or variable economic signals.

A first step is to recognize that the operational c

hallenges facing CAISO, municipal utilities and

distribution grid operators are driving the need fo

r a new set of responsive DER capabilities with

distinctly different characteristics.

Traditional demand response works very well to ad

dress

predicable, discrete peak demand events and as an e

mergency resource for operators. However, much

of this value erodes as the power system becomes mo

re unpredictable and variable that requires much

shorter response times to ensure reliable system op

eration. Therefore,

the relatively analog, slow,

inflexible and imprecise qualities that largely def

ine existing demand response programs may be

surpassed in their relevance and value.

As such, new capabilities should be identified as p

art of the distribution planning process. It is imp

ortant

that the analytical framework identify new criteria

for performance of individual DER technologies.

Performance would include the expected outputs, dur

ation, and operational times. Criteria could

address preferred resources for each individual tec

hnology, or a combination to satisfy specific grid

reliability needs in place of traditional investmen

ts.

In addition to DER services definition, new multi-l

ayer distributed control schemes will be required t

integrate a large number of distributed resources i

nto integrated grid operations. This type of approa

would allow the bulk power, distribution and custom

er/merchant the opportunity to autonomously

optimize for their needs while also maintaining coo

rdination between and across each tier.

This

means, for example, some of this coordination may i

nvolve ensuring that autonomous control settings

of DER devices are appropriately set for certain gr

id conditions occurring and responding appropriatel

This distributed architecture with autonomous contr

ols on customer devices can both mitigate problems

created by high penetrations of DER at distribution

, while also allowing for reliable dispatch across

the T-

D interface. A critical first step to enabling thi

s coordination will be for DSO’s and DER operators

launch pilot projects that seek to integrate advanc

ed DER functionalities into DSO operations.

Transparent Value Identification & Monetization

As a foundation, customers should transparently see

the benefits and costs related to a more

distributed system including their choices in the c

ontext of related system upgrades and operational

expense. This allows customers to weigh those benef

its and costs in terms of affordability, reliabilit

y, the

environment and safety. Customers and services fir

ms should also know what types of services and

benefits they can provide to the grid through acces

s to relevant information. All system participants

should also abide by the same operational rules to

ensure reliability and safety.

A significant challenge with integration of DER is

developing and implementing appropriate value

monetization methods.

Valuation will necessarily need to consider the l

ocal value as well as the net

system value given the integrated nature of the ele

ctric grid. This means benefits associated with th

e 30

uses identified in figure 5 above may be offset by

system issues such as:

•

Surplus generation in day-time hours requiring incr

easing amounts of renewable generation

curtailment to avoid over-generation, and reliabili

ty problems.

•

Increasing amounts of flexible ramping capacity to

accommodate incremental amounts of solar

generation, both ramping down in the morning when s

olar generation starts, and ramping up in

the afternoon as solar generation decreases while t

he evening peak increases.

•

Diminishing value of incremental solar additions du

e to decreasing contributions to reliability

and decreasing energy value of solar additions as t

he hours of residual need shift to later hours

in the afternoon with increasing amounts of solar a

dditions.

This is not to diminish the value that DER can prov

ide, but to recognize that any value determination

requires holistic analyses, including the contribut

ion other DER technologies could combine with solar

generation to maximize value. As discussed earlier

, an analysis framework and appropriate models are

needed immediately to identify these values. In sev

eral cases, potential value is not easily monetized

it may not clearly involve tangible monetary benefi

ts. Value may exist in mitigating externalities

such as

those involved with customer outages. In other inst

ances, value may be derived by displacing utility

investment. Each of these values will need to be m

onetized through a defined method that

transparently produces value for customers.

For example, the nature and value of reactive power

services is distinctly different than an energy or

peak load response service. Today, capacitor banks,

line regulators and load tap changers manage

reactive power. For new investment, the default cos

t is the lifecycle cost of this equipment. So, life

cycle

cost may be one method for pricing DER provided ser

vice be based on this lifecycle cost, subject to a

procurement similar in concept to the valuation met

hod used for demand response. Or, the sub-minute

time response characteristics and the unique, dynam

ic engineering value for each local distribution ar

that may suggest using stochastic

engineering models and option valuation methods fo

r the valuation.

This may also suggest a tariff based pricing (refle

cting the “option premium”) as opposed to a

dynamically calculated price signal. This example

illustrates the considerations needed to define the

appropriate value determination and monetization me

thod for each of the required operational

services. There is not a one size fits all model an

d pricing methods based solely on energy price ($/k

Wh)

do not appear to be sufficient for grid operational

services.

Open Access Participation

Reducing the barriers to participate in these new s

ervices is a fundamental factor to successfully

integrate flexible DER at the scale envisioned in C

alifornia. It is vital that the current barriers in

volving

participation, complex and expensive measurement an

d verification schemes and related settlement

processes be simplified. Since new DER services re

quire firm, dependable and real-time measurable

response, the complex estimation processes of exist

ing demand response programs will be less of an

issue. However, the measurement is a major issue as

today’s rules were designed for integrating larger

generation. Current thinking is also still largely

centered on the form factor and functions of a util

ity type

meter. There is a need to adapt the rules for small

er distributed resources and reflect the modern

metrology, communication and information management

options available. The current demand

response proceeding on this issue may provide a goo

d starting point. But, given the nature of the

operational services required, it is likely these t

opics will need to be revisited within the next 2 y

ears.

Recommended Reading

Reference papers for deeper discussion:

•

Energy Storage for the Electricity Grid: Benefits a

nd Market Potential Assessment Guide

, Sandia, 2010

•

DR 2.0: The Future of Customer Response

, ADS-LBNL, 2013

New York REV initiative is exploring the value of

externalities related to DER service provision

Stochastic methods are used to evaluate random var

iability which is increasingly an issue on power sy

stems

Guiding Principles for DER Integration into Operati

ons

Based on the workshop discussions, the following gu

iding principles are offered for consideration. The

are aligned with relevant federal and state policie

s, and leverage industry research and best practice

referenced in this paper.

. .

. Integrated Grid Roadmap

Integrated Grid RoadmapIntegrated Grid Roadmap

Integrated Grid Roadmap

Customer adoption of DER holds the promise of enhan

cing the operational, environmental, and

affordability of California’s electric system

This requires “an integrated grid that optimizes th

e power

system while providing safe, reliable, affordable,

and environmentally responsible electricity.”

discussed in the 1

and 2

More Than Smart workshops, California needs to con

sider a more advanced

and highly integrated electric system than original

ly conceived in many smart grid plans. This integra

ted

grid will evolve in complexity and scale over time

as the richness of systems functionality will incre

ase

and the distributed reach will extend to millions o

f intelligent utility, customer and merchant device

The conceptual roadmap below outlines a path that b

ridges the divide from today’s realities to the

opportunities envisioned in a more distributed futu

re. This path is focused on the regulatory and

industry actions needed over the next 1 to 3 years

on the cross-cutting issues identified in the prece

ding

sections to enable a graceful transformation of Cal

ifornia’s power system. But, it is important to

recognize the interdependent nature of the distribu

tion life cycle to successfully transition to a hig

value integrated electric distribution network. As

noted in figure 6, many roadmap activities will nee

d to

be executed concurrently. This requires alignment o

f the intricate interdependencies of the various

activities within each stage.

Figure 6: Conceptual More Than Smart Roadmap

This conceptual roadmap is provided only as a start

ing point for a more complete discussion at CPUC

and the 3

More Than Smart workshop. In these forums, conside

ration of the steps needed to scale up

implementation of the comprehensive planning discus

sed. This is non-trivial as there are about 10,000

investor owned utility distribution circuits and se

veral hundred distribution planning areas across

California. Also, pilot implementations of new DER

provided distribution services is needed to

demonstrate the benefits identified in AB327 as wel

l as T-D coordination with CAISO. This specifically

includes operational technology testing and an inte

grated demonstration at sufficient scale to validat

operational effectiveness. This is needed because C

alifornia has yet to test fast response DER

performance in distribution or in a coordinated ope

ration between distribution utilities and CAISO.

Several pilots, such as SCE’s Preferred Resources P

ilot have been discussed or planned that could serv

this purpose.

The distribution plans that each of the California

IOUs will need to file to comply with AB 327 repres

ent

the first step towards starting to re-shape the dis

tribution grid. One of the key activities that the

CPUC

needs to take ahead of these filings is to provide

guidance to the IOUs to ensure that their plans

integrate many of the principles articulated in thi

s paper. The role of this paper is to provide a set

strategic frameworks and guiding principles that ca

n inform stakeholders and policymakers in the

development of the guidelines for AB 327 Distributi

on Plans that the CPUC will eventually ratify.

Additionally, as other states and international loc

ales consider a more distributed electric system th

paper offers guidance on the critical questions and

a framework for developing the path forward for

their particular distribution systems.

Appendix A

Appendix AAppendix A

Appendix A: Relevant California Policies

: Relevant California Policies: Relevant California Policies

: Relevant California Policies

The following list highlights relevant California p

olicy and CPUC proceedings related to distribution

planning, design-build, operations and integration

of DER. This is only a representative list to show

the

range and diversity of policy and activity that dir

ectly or indirectly impacts the distribution system

California Policies (sample)

AB 32; California Global Warming Solutions Act

SB1X 2; 33% RPS standard by 2020

State Water Board Policy on the Use of Coastal and

Estuarine Waters for Power Plant Cooling; (Once

Through Cooling)

Title 24; Residential & Commercial ZNE building cod

Executive Order B-16-2012; Electric Vehicle and Zer

o Emissions Vehicle targets

AB 758; Energy Efficiency Law

AB 2514; Energy Storage goals

SB 17; Smart Grid Systems

AB 327; Changes to Public Utilities Code Section 76

AB 340; Electric Program Investment Charge (EPIC)

CPUC Regulatory Proceedings (sample)

IOU General Rate Cases

08-12-009 Smart Grid (annual plan submissions)

10-12-007 Energy Storage

11-09-011 Interconnection OIR

11-10-023 Resource Adequacy & Local Procurement

12-06-013 Residential Rate Design

13-12-010, 12-03-014, 10-05-006 Procurement Policie

s & Long-term Procurement

13-09-011 Demand response

13-11-007, 09-08-009 Alternative Fueled Vehicles

13-11-006 Operational Risk-based Decision Framework

1405003/4/5 Investor-Owned Utility EPIC Triennial I

nvestment Plans

Appendix B

Appendix BAppendix B

Appendix B: AB 327 Sec. 8

: AB 327 Sec. 8: AB 327 Sec. 8

: AB 327 Sec. 8

California AB 327 Section 8 language regarding dist

ributed resource consideration in planning and

integration into operations.

“Section 769 is added to the Public Utilities Code

, to read:

769. (a) For purposes of this section, “distributed

resources” means distributed renewable generation

resources, energy efficiency, energy storage, elect

ric vehicles, and demand response technologies.

(b) Not later than July 1, 2015, each electrical c

orporation shall submit to the commission a distrib

ution

resources plan proposal to identify optimal locatio

ns for the deployment of distributed resources. Eac

proposal shall do all of the following:

(1) Evaluate locational benefits and costs of dist

ributed resources located on the distribution syste

This evaluation shall be based on reductions or inc

reases in local generation capacity needs, avoided

increased investments in distribution infrastructur

e, safety benefits, reliability benefits, and any o

ther

savings the distributed resources provides to the e

lectric grid or costs to ratepayers of the electric

corporation.

(2) Propose or identify standard tariffs, contract

s, or other mechanisms for the deployment of cost-

effective distributed resources that satisfy distri

bution planning objectives.

(3) Propose cost-effective methods of effectively

coordinating existing commission-approved programs,

incentives, and tariffs to maximize the locational

benefits and minimize the incremental costs of

distributed resources.

(4) Identify any additional utility spending neces

sary to integrate cost-effective distributed resour

ces

into distribution planning consistent with the goal

of yielding net benefits to ratepayers.

(5) Identify barriers to the deployment of distrib

uted resources, including, but not limited to, safe

standards related to technology or operation of the

distribution circuit in a manner that ensures reli

able

service.

resources plan proposal submitted by an electrical

corporation and approve, or modify and approve, a d

istribution resources plan for the corporation. The

commission may modify any plan as appropriate to mi

nimize overall system costs and maximize

ratepayer benefit from investments in distributed r

esources.

(d) Any electrical corporation spending on distrib

ution infrastructure necessary to accomplish the

distribution resources plan shall be proposed and c

onsidered as part of the next general rate case for

the corporation. The commission may approve propose

d spending if it concludes that ratepayers would

realize net benefits and the associated costs are j

ust and reasonable. The commission may also adopt

criteria, benchmarks, and accountability mechanisms

to evaluate the success of any investment

authorized pursuant to a distribution resources pla

n.”

Appendix C:

Appendix C: Appendix C:

Appendix C: Value of the Grid

Value of the Grid Value of the Grid

Value of the Grid

The value of the electric grid given potential grow

th of customer self-sufficiency or independent micr

o-grids

is an open question. In this context, the discussio

n at the 2

MTS workshop identified a “node-friendly”

network

model as the desired among four potential distribu

tion end-states and related value of the grid.

The four end-states below should be viewed as on a

continuum in terms of the value of the grid.

Grid as Back-up

This end-state involves a majority of customers bec

oming largely self-sufficient through the adoption

distributed resources including energy storage and

advanced building and home energy management

systems. This end-state envisions a smaller number

of customers remaining wholly dependent on the

integrated electric system and a growing number of

former customers that have become totally self-

sufficient and have disconnected. Independently own

ed community microgrids arise displacing need for

utility distribution investment. Utility investment

in electric distribution diminishes, focused prima

rily on

break-fix to maintain minimal service standards and

quality.

Current Path

This end-state is based on the current utility inve

stment plans for electric distribution refresh and

smart grid

technology adoption as identified in current rate c

ases and smart grid roadmaps. This end-state assume

s an

incremental and reactive approach to infrastructure

investment. Lack of coordination or collaboration a

mong

stakeholders can create gaps in system planning and

investment. This creates a risk of misalignment of t

timing and location of advanced technology investme

nt or substantive changes in distribution design wi

th the

pace of customer and merchant DER penetration.

Grid as Network

This end-state builds on the current investments th

rough an acceleration of more advanced technology

adoption into the grid along with an evolution of d

istribution system designs to create a node-friendl

y grid to

enable seamless integration of DER and independent

microgrids. This envisions a proactive approach to

manage the alignment of investment to enable the ad

option of DER. This open electric network platform

and

related operations enables upwards of 20 GWs of dis

tributed energy resources and over 1.5 million elec

tric

vehicles to integrate safely and reliably while als

o contributing to the improved overall efficiency o

f CA’s

electric system.

Network in this context refers to an open, multi-d

irectional electric distribution system that create

s additional

value for connected customers and distributed energ

y resources. It does not refer to, but doesn’t prec

lude, the

type of electrical distribution configuration that

links the secondaries of multiple distribution circ

uits into a mesh

configuration for enhanced reliability.

Convergence

This end-state envisions the convergence of an inte

grated electric network with California’s water,

natural gas and transportation systems to create mo

re efficient and resilient infrastructure to enable

the

state’s long-term economy and environmental policy

objectives. Convergent opportunities to minimize

capital investment in infrastructure for synergisti

c societal benefits are fully evaluated in local jo

int

planning efforts. Advanced operational data and co

ntrol technologies are increasingly integrated in

highly coordinated operations across the water, nat

ural gas, and transportation networks.