DRAFT 

NIST Framework and Roadmap 

for Smart Grid Interoperability 

Standards, Release 4.0

Avi Gopstein

Cuong Nguyen

Cheyney O’Fallon

Nelson Hastings

David Wollman
DRAFT

NIST Framework and Roadmap 

for Smart Grid Interoperability 

Standards, Release 4.0

Avi Gopstein, Cuong Nguyen, Cheyney O’Fallon, and David Wollman

Smart Grid and Cyber-Physical Systems Program Office

Engineering Laboratory

Nelson Hasting

Applied Security Division

Information Technology Laboratory

July 2020

U.S. Department of Commerce 

Wilbur L. Ross, Jr., Secretary

National Institute of Standards and Technology 

Walter Copan, NIST Director and Undersecretary of Commerce for Standards and Technology 
Certain commercial entities, equipment, or materials may be identified in this

document in order to describe an experimental procedure or concept adequately.

Such identification is not intended to imply recommendation or endorsement by the

National Institute of Standards and Technology, nor is it intended to imply that the

entities, materials, or equipment are necessarily the best available for the purpose. 
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Key Messages – NIST Smart Grid Interoperability Framework

Interoperability — the ability to exchange information in a timely, actionable manner — is a 

critical yet underdeveloped capability of the power system. Significant grid modernization 

has occurred in recent years, but the proliferation of technology and associated standards has 

only modestly improved interoperability.

The expansion of distributed energy resources and other technologies, along with changing 

customer expectations, have complicated the interoperability challenge. This revision of the 

NIST Smart Grid Interoperability Framework uses evolving technology and power system 

architectures as context for describing a new set of interoperability perspectives.

Distributed and customer-sited resources figure prominently in the future smart grid, as do 

intelligent distribution systems and other key integrators. As society modernizes the physical 

mechanisms by which we produce, manage, and consume electricity, strategies for system 

operations and economic structure will diversify. This diversification will benefit from —

and eventually rely upon — enhanced interoperability.

The benefits of interoperability are broad and reach all stakeholders at all scales. 

Interoperability is a hedge against technology obsolescence, maximizes the value of 

equipment investments by increasing usage for secondary purposes, and facilitates 

combinatorial innovation by allowing coordinated small actions across diverse stakeholders 

and devices to have grand impacts. The interoperability value proposition can be realized in 

any system domain, from the utility to the customer and beyond.

Interoperability requires a cybersecurity approach that manages risk while opening new 

communication interfaces. The desired outcomes for the grid and the information exchanges 

that must be protected will have to be considered in concert and will benefit from a structured 

approach to system security. New interfaces can benefit from existing security processes.

Testing and certification is a critical enabler of smart grid interoperability. However, the 

current industry focus on certifying conformance to individual standards is only the first step 

on the pathway to assuring interoperability for devices or systems, and cannot provide 

interoperability without significant additional effort.

Interoperability Profiles are a proposed solution to the interoperability challenge. Built upon 

concepts of physical and informational interoperability and drawn from existing standards, 

these Profiles describe a subset of requirements that — when implemented and verified 

through testing and certification — would ensure interoperability across devices and systems. 
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Acknowledgements

This Framework is the result of an ongoing collaborative effort involving many individuals 

and organizations across industry, academia, and government. Through six public 

workshops and additional presentations, more than 300 attendees and speakers provided 

invaluable feedback which helped ensure that this document reflects a broad set of

stakeholder perspectives regarding the issues surrounding smart grid interoperability.

The authors would like to thank Christopher Greer for his invaluable guidance, support, and 

extensive reviews throughout the Framework development process. This document is far 

better for his contributions.

Many others have provided important ideas and facilitated processes that are the foundations 

for this Framework. The contributions of the following individuals were especially 

noteworthy and appreciated: Jason Allnutt, Dhananjay Anand, Paul Boynton,

Danielle Byrnett, Christopher Irwin, Konstantina Di Menza, Amimul Ehsan, Thomas Linn, 

Jeffrey Marron, Aaron Smallwood, Ravi Subramaniam, Jeffrey Taft, Christopher Villarreal, 

and Kerry Worthington.
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Table of Contents

Key Messages.................................................................................................................i

Acknowledgements.......................................................................................................ii

List of Figures.............................................................................................................vii

List of Tables .............................................................................................................viii

List of Acronyms.........................................................................................................ix

Purpose and Scope ................................................................................................ 1

1.1. Overview and Background....................................................................................... 1

1.2. The Role of Interoperability..................................................................................... 3

1.2.1. The interoperability value proposition ..............................................................................3

1.2.2. The empowered consumer ................................................................................................5

1.2.3. Interoperability and customer value..................................................................................6

1.2.4. Utility and Other Benefits.................................................................................................7

1.3. Framework Content and Structure ......................................................................... 8

1.3.1. The role of grid architecture..............................................................................................8

1.3.2. Updated models.................................................................................................................9

1.3.3. A common language for the grid.......................................................................................9

1.3.4. Tools to facilitate interoperability.....................................................................................9

1.4. Use of this Framework.............................................................................................. 9

Models for the Smart Grid ................................................................................. 10

2.1. NIST Smart Grid Conceptual Model .................................................................... 10

2.1.1. Conceptual model updates ..............................................................................................12

2.1.2. Conceptual model domains.............................................................................................13

2.2. Communication Pathways Scenarios..................................................................... 15

2.2.1. Graphic conventions........................................................................................................15

2.2.2. The legacy communication pathways scenario...............................................................16

2.2.3. High-DER communication pathways scenario ...............................................................17

2.2.4. Hybrid communication pathways scenario .....................................................................20

2.2.5. Microgrid communication pathways scenario ................................................................21

2.3. An Ontology for the Smart Grid............................................................................ 22

2.3.1. The NIST framework for cyber-physical systems ..........................................................23

2.3.2. The aspects of a modern electrical grid...........................................................................24

2.3.3. Aspects and concerns of the electrical grid.....................................................................26

3 Operations............................................................................................................ 27

3.1 Interoperability for Utilities................................................................................... 29

3.1.1 System composition and constructivity...........................................................................29

3.1.2 Hedging against obsolescence.........................................................................................30

3.2 Interoperability for New Technology .................................................................... 31

3.2.1 Changing physics at the edge of the system....................................................................31

3.2.2 Changing supply and demand technology ......................................................................33

3.2.3 Alternating and direct current interactions......................................................................34
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3.2.4 Electric vehicles and a changing infrastructure...............................................................35

3.3 Evolving Control Schemes...................................................................................... 35

3.3.1 Utility-driven control schemes........................................................................................36

3.3.2 Emerging customer-driven control schemes...................................................................37

3.3.3 System devolution...........................................................................................................39

3.4 Emerging Interoperability Requirements............................................................. 39

3.4.1 Requirements for metrology, observability, and controllability .....................................40

3.4.2 Trustworthiness...............................................................................................................44

3.5 Interoperability for Customer Empowerment ..................................................... 45

3.6 Future Work ............................................................................................................ 46

4 Economics ............................................................................................................ 47

4.1 Economics of the Conventional Utility .................................................................. 48

4.1.1 Functions of electric utilities...........................................................................................48

4.1.2 Cost structures.................................................................................................................49

4.1.3 Ratemaking .....................................................................................................................49

4.2 Evolution of the Distribution Utility...................................................................... 50

4.2.1 Changes to utility organizational structure......................................................................50

4.2.2 Performance-based regulation.........................................................................................51

4.2.3 Economics of changing operations .................................................................................52

4.3 Factors Affecting — and Benefits From — Interoperability .............................. 53

4.3.1 Interoperability and specificity........................................................................................54

4.3.2 Interoperability and customer empowerment..................................................................54

4.3.3 Complexity and cost structures.......................................................................................55

4.3.4 Trust and assurance .........................................................................................................56

4.3.5 Testing and certification..................................................................................................57

4.4 Economics and Challenges of Certification Institutions...................................... 57

4.4.1 Challenge: consumer demand .........................................................................................58

4.4.2 Challenge: interdependence and accountability..............................................................59

4.4.3 Challenge: concentration of market power .....................................................................59

4.4.4 Challenge: consumer vigilance .......................................................................................59

4.5 Interoperability Benefits......................................................................................... 59

4.5.1 Minimizing transaction costs ..........................................................................................59

4.5.2 Creating value .................................................................................................................60

4.6 Conclusion and Future Work................................................................................. 61

5 Cybersecurity....................................................................................................... 62

5.1 Securing Organizations........................................................................................... 64

5.1.1 NIST cybersecurity framework core functions...............................................................64

5.1.2 NIST cybersecurity framework core categories and subcategories ................................65

5.1.3 Cybersecurity profiles.....................................................................................................67

5.1.4 Cybersecurity framework profile for the smart grid .......................................................68

5.2 Securing Information Exchange ............................................................................ 71

5.2.1 Known system interfaces and categories.........................................................................71

5.2.2 New system interfaces.....................................................................................................72
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5.2.3 Assessing security requirements of new interfaces.........................................................74

5.3 Additional Cybersecurity Resources..................................................................... 76

5.4 Conclusions and Future Work ............................................................................... 77

6 Testing and Certification.................................................................................... 79

6.1 The Role of Testing and Certification ................................................................... 80

6.1.1 Testing and certification value ........................................................................................80

6.1.2 Current practice...............................................................................................................81

6.2 Levels of Interoperability ....................................................................................... 81

6.3 Types of Testing Processes...................................................................................... 83

6.3.1 Conformance and interoperability testing.......................................................................84

6.3.2 Interoperability tests........................................................................................................84

6.3.3 Certification regimes.......................................................................................................85

6.4 Current Smart Grid Testing Initiatives ................................................................ 86

6.4.1 Testing support................................................................................................................86

6.4.2 Catalog of standards........................................................................................................86

6.4.3 Catalog of test programs .................................................................................................87

6.4.4 Reference interoperability procurement language ..........................................................88

6.5 Towards Interoperability Profiles ......................................................................... 89

6.5.1 Interoperability profiles...................................................................................................89

6.5.2 Example of an interoperability profile ............................................................................90

6.5.3 Interoperability profiles work plan..................................................................................92

6.5.4 Open source test tool development .................................................................................92

6.6 Conclusions and Future Work ............................................................................... 93

Conclusion............................................................................................................ 94

Appendix A – Smart Grid Conceptual Model Domains ........................................ 97

A.1 - Customer Domain .................................................................................................... 97

A.2 - Markets Domain..................................................................................................... 100

A.3 - Service Provider Domain....................................................................................... 103

A.4 - Operations Domain................................................................................................ 106

A.5 - Generation Including DER Domain..................................................................... 109

A.6 - Transmission Domain............................................................................................ 112

A.7 - Distribution Domain .............................................................................................. 114

Appendix B – Mapping CPS Aspects and Concerns to the Electrical Grid.......116

Appendix C – Inverter and DER Functions..........................................................146

Appendix D – The Core Set of Electric Industry Roles........................................151

Appendix E – Cost Recovery, Rate Design, and Regulation................................153

Appendix F – Distribution Platforms and Markets..............................................156
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Appendix G – Smart Grid Cybersecurity Profile Subcategory Prioritization and 

Considerations Matrices..........................................................................................158

G.1 – Identify Function................................................................................................... 158

G.2 – Protect Function.................................................................................................... 165

G.3 – Detect Function...................................................................................................... 173

G.4 – Respond Function.................................................................................................. 176

G.5 – Recover Function .................................................................................................. 179

Appendix H – Logical Interface Categories from NISTIR 7628.........................180

Appendix I – Types of Information Exchange Between Entities in the High-DER 

Example.....................................................................................................................183

Appendix J – List of Reviewed Smart Grid Interoperability Standards ...........195

References.................................................................................................................202
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List of Figures

Figure 1 – Installed photovoltaic price trends over time [12]................................................... 2

Figure 2 – Interoperability across scales................................................................................... 5

Figure 3 – Customer and consumer benefits from the smart grid............................................. 7

Figure 4 – Updated NIST smart grid conceptual model......................................................... 11

Figure 5 – Legacy communication pathways scenario........................................................... 17

Figure 6 – High-DER communication pathways scenario ..................................................... 19

Figure 7 – Hybrid communication pathways scenario ........................................................... 21

Figure 8 – Microgrid communication pathways scenario....................................................... 22

Figure 9 – CPS framework domains, facets, and aspects....................................................... 24

Figure 10 – Example electrical waveform distortions observed in NIST experiments.......... 33

Figure 11 – The NIST High DER Communication Pathways Scenario, highlighting a 

representation of utility direct load control programs............................................................. 38

Figure 12 – The NIST Microgrid Communication Pathways Scenario, highlighting a 

representation of utility voluntary load curtailment programs for industrial and commercial 

customers ................................................................................................................................ 38

Figure 13 – Smart meter accuracy under high harmonic waveform loads............................. 41

Figure 14 – Example smart meter measurement accuracies for highly distorted waveforms 42

Figure 15 – Wide area precision time requirements in power systems .................................. 43

Figure 16 – State-level absolute and per-customer electricity consumption trends ............... 51

Figure 17 – Example of cybersecurity Considerations for the electrical system.................... 69

Figure 18 – Smart Grid Profile excerpt................................................................................... 70

Figure 19 – Logical Interface Reference Model "Spaghetti Diagram" from NISTIR 7628... 72

Figure 20 – Example logical interfaces in a High-DER architecture ..................................... 74

Figure 21 – Logical interface categories (LICs) for the High-DER example......................... 75

Figure 22 – Levels of interoperability conceptual diagram.................................................... 82

Figure 23 – Testing and certification development process ................................................... 83

Figure 24 – Interoperability standards and associated testing and certification ..................... 88

Figure 25 – Potential implementation combinations for IEEE 1547-2018............................. 90

Figure 26 – California Rule 21 interoperability profile implementation................................ 91

Figure 27 – Overview of the Customer domain...................................................................... 97

Figure 28 – Overview of the Markets domain...................................................................... 100

Figure 29 – Overview of the Service Provider domain ........................................................ 103

Figure 30 – Overview of the Operations Domain................................................................. 106

Figure 31 – Overview of the Generation Including DER Domain ....................................... 109

Figure 32 – Overview of the Transmission domain.............................................................. 112

Figure 33 – Overview of the Distribution domain................................................................ 114
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List of Tables

Table 1 – Domains and roles/services in the smart grid conceptual model............................ 14

Table 2 – Domain descriptions and graphical color representation........................................ 16

Table 3 – Communication pathways diagrams symbol descriptions...................................... 16

Table 4 – Cybersecurity Framework functions and categories............................................... 66

Table 5 – Cybersecurity Framework subcategory examples.................................................. 67

Table 6 – Certification regime characteristics (illustrative) ................................................... 86

Table 7 – Typical application categories in the Customer domain......................................... 99

Table 8 – Typical applications in the Markets domain......................................................... 102

Table 9 – Typical applications in the Service Provider domain ........................................... 105

Table 10 – Typical applications in the Operations domain .................................................. 107

Table 11 – Typical applications requiring interoperability in the Generation Including DER 

domain................................................................................................................................... 111

Table 12 – Typical applications in the Transmission domain .............................................. 113

Table 13 – Typical applications within the Distribution domain ......................................... 115

Table 14 – Mapping CPS Aspects and Concerns to the electrical grid ................................ 116

Table 15 – Inverter and DER functions: mandatory, autonomous, and market-based ......... 146

Table 16 – Identify function subcategory prioritization and considerations ........................ 158

Table 17 – Protect function subcategory prioritization and considerations.......................... 165

Table 18 – Detect function subcategory prioritization and considerations........................... 173

Table 19 – Respond function subcategory prioritization and considerations....................... 176

Table 20 – Recover function subcategory prioritization and considerations........................ 179

Table 21 – Logical Interface Categories from NISTIR 7628 [126]...................................... 180

Table 22 – Information exchanges in Figure 21 High-DER example .................................. 183

Table 23 – List of standards reviewed for testing and certification availability................... 195
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List of Acronyms

AC Alternating Current 

ADMS Advanced Distribution Management System

AGC Automatic Generation Control 

AMD Amendment

AMI Advanced Metering Infrastructure 

ANSI American National Standards Institute

ASHRAE American Society of Heating, Refrigerating and Air-Conditioning Engineers

B2B Business-to-business

BACNet Building Automation and Control Networks

BAS Building Automation System 

BES Bulk Energy System

BTM Behind the Meter 

C&I Commercial and Industrial

CapEx Capital Expenditures 

CBM Condition-Based Maintenance 

CCA Community Choice Aggregation

CEA Consumer Electronics Association

CFL Compact Fluorescent Lamp

CIM Common Information Model

CIP Critical Infrastructure Protection 

CIS Customer Information System 

CIS CSC Center for Internet Security Critical Security Controls

CME Chicago Mercantile Exchange 

COBIT Control Objectives for Information Technologies

ComEd Commonwealth Edison

COS Catalog of Standards 

CoTP Catalog of Test Programs 

COTS Commercial Off-the-Shelf 

CPS Cyber-Physical Systems 

CPUC California Public Utilities Commission

CSR Customer Service Representative 

CTA Consumer Technology Association

CVR Conservation Voltage Reduction 

DC Direct Current 

DCS Distributed Control System

DDC Distributed Data Collector 

DER Distributed Energy Resources 

DERMS Distributed Energy Resource Management System 

DG Distributed Generation 
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DLC Direct Load Control 

DMS Distribution Management System 

DNP Distributed Network Protocol 

DOE Department of Energy 

DoS Denial of Service 

DR Demand Response

DRMS Demand Response Management System 

DSO Distribution System Operators 

ECP Electrical Connection Point

EMI Electromagnetic Interference

EMIX Energy Market Information Exchange

EMS Energy Management System 

EPRI Electric Power Research Institute

EPS Electric Power System

ERCOT Electric Reliability Council of Texas

ESI Energy Services Interface 

ESP Energy Service Provider 

EUMD Energy Usage Metering Device

EV Electric Vehicles 

EVSE Electric Vehicle Supply Equipment

FDEMS Facilities DER Energy Management System 

FERC Federal Energy Regulatory Commission

FLISR Fault Location, Isolation, and Service Restoration

FSGIM Facility Smart Grid Information Model

GHG Greenhouse Gas

GIS Geographic Information System 

GMLC Grid Modernization Laboratory Consortium 

GNSS Global Navigation Satellite System 

GOOSE Generic Object Oriented Substation Events

GPS Global Positioning System

GWAC GridWise Architecture Council 

HAN Home Area Network 

HVAC Heating, Ventilation, and Air Conditioning

ICAP IEEE Conformity Assessment Program 

ICS Industrial Control System 

ICT Information and Communications Technology 

IDS Intrusion Detection Systems 

IEC International Electrochemical Commission 

IED Intelligent Electronic Devices 

IEEE Institute of Electrical and Electronics Engineers
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IETF Internet Engineering Task Force

IoT Internet of Things 

IOU Investor Owned Utility 

IP Internet Protocol

IPRM Interoperability Process Reference Manual 

IRM Interface Reference Model 

ISA International Society of Automation

ISO Independent System Operators 

ISO International Organization for Standardization

IT Information Technology 

ITCA Independent Testing and Certification Authority 

ITU International Telecommunication Union

kWh kilowatt-hour

LAN Local Area Network 

LED Light Emitting Diode

LIC Logical Interface Categories 

LMS Load Management System 

MDMS Meter Data Management System 

MIB Management Information Base

MISO Midcontinent Independent System Operator 

MQTT Message Queuing Telemetry Transport

MWh Megawatt-hour

NAESB North American Energy Standards Board

NEMA National Electrical Manufacturers Association

NERC North American Electric Reliability Corporation 

NIST National Institute of Standards and Technology 

NISTIR NIST Interagency Report

NYMEX New York Mercantile Exchange 

O&M Operating and Maintenance 

OASIS Organization for the Advancement of Structured Information Standards

OCPP Open Charge Point Protocol 

OGCGML Open Geospatial Consortium – Geography Markup Language

OMM Operation, Maintenance and Monitoring 

OMS Outage Management System 

OPC-UA Open Platform Communications Unified Architecture

OpenADR Open Automated Demand Response

OSI Open Systems Interconnection 

OT Operational Technology 

PCC Point of Common Coupling
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PEV Plug-in Electric Vehicles 

PF Power Factor

PICS Protocol Implementation Conformance Statement 

PII Personally Identifiable Information 

PIM Performance Incentives Mechanisms 

PJM PJM regional transmission organization

PMU Phasor Measurement Units 

PUC Public Utilities Commission

PV Photovoltaics

PWG Public Working Group 

RBAC Role-based Access Control 

REP Retail Energy Provider 

ROCOF Rate of Change of Frequency 

ROE Return on Equity 

ROI Return on Investment 

RTO Regional Transmission Organizations 

RTU Remote Terminal Unit

SAE Society of Automotive Engineers

SCADA Supervisory Control and Data Acquisition 

SCED Security Constrained Economic Dispatch 

SEP Smart Energy Profile

SEPA Smart Electric Power Alliance

SIPS System Integrity Protection Schemes 

SNMP Simple Network Management Protocol

SOC State of Charge

SOS Systems of Systems 

SPI Sensitive Personal Information 

T&C Testing and Certification 

TBLM Transmission Bus Load Model 

TI Time Intervals 

TOU Time of Use

TSS Test Suite Specification 

UCAIug Utility Communications Architecture International Users Group

VAR Volt-ampere reactive

Volt-Var Voltage-reactive power mode for inverter/DER control

VPN Virtual private network

VVO Volt/VAR Optimization 

WAMS Wide Area Management System

WAN Wide Area Network

WAPOD Wide Area Power Oscillation Damping 
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WASA Wide-area Situational Awareness 

Watt-PF Active power-power factor mode for inverter/DER control

Watt-Var Active power-reactive power mode for inverter/DER control

WMS Work Management System 

XMPP Extensible Messaging and Presence Protocol
1

This publication is available free of charge from: https://doi.org/10.6028/NIST.SP.XXX This DRAFT publication is provided for public comment, and is available from: https://www.nist.gov/el/smart-grid/smart-grid-framework This DRAFT report is provided for public comment, and is available from: https://www.nist.gov/el/smart-grid/smart-grid-framework

1 Purpose and Scope

2

3 It is the policy of the United States to support the modernization of the Nation’s 

4 electricity transmission and distribution system ...The National Institute of 

5 Standards and Technology shall have the primary responsibility to coordinate 

6 the development of a framework that includes protocols and model standards 

7 for information management to achieve interoperability of smart grid devices 

8 and systems.

9 Energy Independence and Security Act of 2007 [1]

10

11

12 The United States power system encompasses more than 7,000 power plants [2] feeding a 

13 distribution system with 6,000,000 miles of wire serving 150,000,000 customers [3]. This 

14 immense system, integrated into every aspect of modern life, has provided inexpensive, 

15 reliable power for decades. It is also in the midst of a dramatic transformation that changes 

everything from how energy is produced1 16 to how it is consumed [5]. 

17

18 The electrical grid is the tightly coupled system that manages and delivers power from where 

19 and how it is generated to where—and how—it is consumed. The Nation needs an electrical 

20 grid that is adaptable, secure, reliable, resilient, and can accommodate changing loads, 

21 generation technologies, and operating business models. Grid modernization will bring new 

22 capabilities and economic opportunity to utilities and customers through improved access to 

23 data, cyber security protections, and power flow control, but will also require new physical 

24 and informational capabilities to observe and manage the system and its emerging and 

25 increasingly complex dynamics [6]. Interoperability is the crucial enabler of these needed 

26 capabilities.

27

28 1.1. Overview and Background

29

30 Technological advances are transforming the electric grid. Over the last decade, the United 

31 States has experienced large increases in the deployment and use of nontraditional energy 

32 resources [7]. As the installed costs for technologies like solar photovoltaics (PV) continue 

33 their dramatic decline (see Figure 1), deployments are expected to rise significantly [8]. But 

34 generation is only one part of the system, and the largest category of distributed energy 

35 technologies in use today — demand response — is focused on optimizing electricity 

36 consumption rather than production [9]. And as the capabilities of modern power electronics 

37 expand, new sources of essential reliability services are emerging [10]. The power grid will 

38 become more resilient as these capabilities are deployed across a broadening range of 

39 applications and scales [11].

1 In the year 2000 the United States produced more than 200 times as much electricity from oil than from solar energy. Over 

the next 15 years solar power generation grew by almost 30% annually while oil-based generation fell by nearly 9% per 

year; by 2015 the amount of electricity generated from both resources were similar. In the years since solar generation grew 

at nearly 40% per year while oil generation continued to decline, so that in 2018 nearly 3 kWh of solar power were 

generated for each kWh of oil-fueled electricity [4].
2

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1

2 Figure 1 – Installed photovoltaic price trends over time [12]

3 The modular and scalable nature of modern energy technologies [13] also allows for 

4 distributed implementations of grid capabilities which have historically been provided 

5 through large and centralized utility infrastructures. These changes, combined with 

6 regulatory changes that have altered the historic guarantee for a utility’s return on capital 

7 investment, have over time reduced the unit size of newly deployed generation [6] and 

8 allowed generation and demand management capabilities to expand toward the grid edge 

9 [14]. This evolving set of resources and capabilities are conventionally referred to as 

10 Distributed Energy Resources (DERs).

11

Because electricity is perishable, most power is delivered at the time it is generated.2 12 The 

13 supply, transmission, distribution, and consumption of electricity in the system are therefore 

14 closely coupled, and must be actively coordinated [16]. This requires the coordinated 

15 sensing, measurement, and control of devices and systems spread across the grid. 

16 Fortunately, the cost of sensors has declined even more rapidly than the cost of energy 

17 technologies, and the growth of sensing and network enabled energy devices and systems is 

18 unleashing dramatic opportunities to improve our ability to understand and operate the power 

19 grid [17]. Interoperability is the key to unlocking this potential.

2 Energy storage provides temporal flexibility and has an increasing role in the system. However, the scale of energy 

storage deployments of all kinds remains small compared to the grid’s net generating capacity [15].
3

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1 1.2. The Role of Interoperability

2

3 These [interoperability] protocols and standards shall further align policy, 

4 business, and technology approaches in a manner that would enable all electric 

5 resources, including demand-side resources, to contribute to an efficient, 

6 reliable electricity network.

7 Energy Independence and Security Act of 2007

8

9 In our work, we define interoperability as the capability of two or more networks, systems, 

10 devices, applications, or components to work together, and to exchange and readily use 

information — securely, effectively, and with little or no inconvenience to the user.3 11 The 

12 smart grid will be a system of interoperable systems; that is, different systems will be able to 

13 exchange meaningful, actionable information in support of the safe, secure, efficient, and 

14 reliable operations of the grid [19]. As the number of devices and systems used on the 

15 electrical grid continue to multiply [20], the interoperability requirements become more 

16 complex and the path to achieving interoperability becomes more challenging.

17

18 1.2.1. The interoperability value proposition

19

20 Modern energy systems rely on an increasing array of sophisticated controls and information 

21 exchanges which are managed across diverse operational and economic systems [21]. 

22 Interoperability is therefore key to maximizing the benefits of technology investments. Yet 

23 because it is not easy to directly quantify the value of seamlessly exchanging a single bit of 

24 information in a complex system like the electrical grid, the value of interoperability is most 

25 often thought of in the context of what is avoided: the expensive and time consuming set of 

26 activities necessary for one-off integrations of incompatible systems [22]. Indeed, anecdotes 

27 abound regarding the expense and functional limitations associated with integrating 

28 equipment designed to conform to the same interoperability standard [23]. For equipment 

29 designed to dissimilar standards, the challenges of achieving the intended functionality can 

30 become difficult to overcome. 

31

32 Beyond minimizing system integration costs, grid interoperability also creates new value 

33 throughout the smart grid. As tens of billions of dollars are spent annually on 

34 communications-capable electrical devices and software, the transition from isolated and 

35 siloed capabilities to interconnected systems will engender tremendous economic and 

36 operational opportunities across society [17]. Empowering consumers to better manage their 

37 energy consumption is but one of the growing set of capabilities that interoperability enables, 

38 which together will impact every aspect of how electricity is produced and managed and 

39 provide fundamentally new and different value propositions.

40

41 Beginning with individual sensors and devices found in the home, Figure 2 depicts how the

42 impacts of interoperability can change with the scale of interaction. Each level of the 

3 While the IEEE definition of interoperability [18] provides that interoperability is the “ability of two or more systems or 

components to exchange information and use the information that has been exchanged,” we extend that in our work to 

ensure that use is secure, effective, and poses little or no inconvenience to the user.
4

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1 diagram represents a new set of interactions and information exchanges which can lead to 

2 new value opportunities. These include:

3

4 Local: Interoperability between individual sensors, energy consuming devices, and 

5 system controllers can allow residential, industrial, and commercial customers to 

6 better monitor their energy demand (or production), and manage consumption 

7 according to their specific needs.

8

9 Proximal: Interoperability at the community level would create opportunity by 

10 allowing customers to interact with and potentially provide services to their 

11 neighbors, aggregators, or distribution utility. Specific community and local 

12 reliability needs could be met by better local management of power flow and quality 

13 issues in the system.

14

15 Regional: Interoperability at the regional level would improve situational and state 

16 awareness for utilities, system operators, and regulators, allowing for more efficient 

17 operation and improved long-term planning. Physical interactions between the 

18 electrical system and the local environment (e.g., managing surface water [24]) could 

19 be better managed, as well.

20

21 Global: At the societal scale, interoperability will enable expanded access to modern 

22 energy services, economic development, and environmental stewardship [25]. 

23

24 While interoperability — or lack thereof — is often considered an issue that must be 

25 addressed for utilities to maximize return on investment for specific system assets [26], 

26 Figure 2 describes a different general concept: that interoperability creates value by 

27 overcoming the designed specificity of energy devices connected to the grid. Breaking this 

28 asset specificity would allow systems purchased to perform one set of tasks the ability to 

29 contribute to an entirely different set of applications by sharing information with a new set of 

30 actors. Value accrues as it flows from local to global levels; for example, as smart load and 

31 DER management at the house contribute to proximal voltage stability and regional balance 

32 of load to renewable energy sources.

33

34 Interoperability is therefore a tool to unlocking new value across the power system. The 

35 benefits can accrue at any scale, and for assets owned by any stakeholder. Some of the most 

36 intriguing implications relate to the role of the energy consumer. 
5

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1

2 Figure 2 – Interoperability across scales

3

4 1.2.2. The empowered consumer

5

6 The power grid was for decades modeled as a simple set of interactions [27]. With simplicity 

7 born of a need for computationally tractable approaches to manage the system, these models 

8 codified the relationships between grid actors in similarly simple terms. In this paradigm 

9 generators produce electricity that is fed to and consumed by customers, and everything on 

10 the system is well characterized with behaviors that are both linear and consistent in their 

11 response.

12

13 Changing technologies have upended these assumptions. The new power grid is increasingly 

14 dynamic [28], few devices interact with the grid in the straightforward linear manner of old 

15 [29], and customers have long-since evolved into providers of resources that actively support 

16 grid health [30]. Indeed, expanding capabilities and falling costs for small-scale energy 

17 technologies have allowed customers and other actors to emerge as entirely new classes of 

18 asset owners. 
6

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1 The empowered energy consumer who can actively manage their interactions with the power 

2 grid is therefore one of the key elements of this Framework. Empowered by integration of 

3 new physical and informational capabilities, consumer devices can manage load, produce 

power, and otherwise support grid health4 4 in ways which defy the historical customer-utility 

5 relationship. As consumer and third-party assets gain capability to respond to economic 

6 opportunity beyond the traditional tariff structure, the relationships between asset owners and 

7 electric utilities will evolve.

8

9 The empowered consumer’s expanding set of roles are depicted in Figure 2, where devices 

10 deployed in the home enable a diverse set of interactions and outcomes. Similar 

11 developments will also occur with commercial and industrial devices and systems.

12

13 1.2.3. Interoperability and customer value

14

15 An empowered energy consumer has many opportunities to obtain value and can optimize 

16 their interactions with the broader energy system to maximize their preferred benefit. 

17 Complementary to the concepts explored in Section 1.2.1 where the value of interoperability 

18 flows outward from technologies in the home to the local community and beyond, 

19 interoperability also allows customers to identify and prioritize interactions optimized to 

20 yield a desired outcome.

21

22 Widespread interoperability will enable interested energy customers to tailor their activities 

23 towards preferred value classes, such as the financial, environmental, reputational, and other 

24 benefits illustrated in Figure 3. Customers could also focus their interactions on metrics 

25 related to a single benefit, such as selling power back to the grid or improving local air 

quality, thereby gaining more direct feedback and perceived value from each action.5 26

27

28 The value opportunities brought to the customer through the smart grid are limited only by 

29 the extent of system interoperability and the pace of innovation. Further discussion on this 

30 issue is found in Section 4.

4 For example, by providing reactive power or voltage support along a distribution feeder.

5 While each customer action likely produces multiple benefits, the ability to track metrics for specific benefits is an 

important mechanism for promoting transparency and stimulating customer action.
7

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1

2 Figure 3 – Customer and consumer benefits from the smart grid

3

4 1.2.4. Utility and Other Benefits

5

6 Interoperability benefits are often reciprocal in nature and can accrue to multiple parties 

7 through diverse interactions. While Figure 2 depicts a value stream emanating from 

8 customer-sited devices, utility investments in interoperable equipment would likely have 

9 similarly far-reaching impacts and provide value to a broad range of stakeholders.

10

11 Recent NIST work has shown that utility-based interoperability investments improve system 

12 resilience, an effect which is conservatively estimated to provide billions of dollars in 

13 economic benefit during natural disasters and potentially savings lives. This resilience 

14 benefit is different from the operational efficiencies traditionally cited as justification for 

15 utility-based interoperability investments [31]. 

16

17 The scope of benefits are only just beginning to be understood for utility or third-party 

18 interoperability investments that enable platforms for innovative grid management, such as 

19 through transactive market signals or peer-to-peer services [32]. 
8

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1 1.3. Framework Content and Structure

2

3 This Framework document reflects the results of the ongoing technical work of the National 

4 Institute of Standards and Technology (NIST) in the area of smart grid interoperability, and 

5 builds on prior Framework versions [19, 33, 34]. This revision examines the impacts 

6 changing grid technologies will have on four key areas, and the associated evolution of grid 

7 interoperability requirements. The four areas are:

8

9 • Grid Operations

10 • Cybersecurity

11 • Grid Economics

12 • Standards Testing & Certification 

13

14 The impact of interoperability on the emerging trends in each of these four focus areas is 

15 explored, and roadmaps for research, standards, and other technical work to advance 

16 interoperability in the smart grid are described. 

17

18 1.3.1. The role of grid architecture

19

20 Grid architecture is the highest level description of the complete grid, and is an important 

21 tool to understand and define the many complex interactions that exist in the electrical 

22 system [35]. The relationships between technology, regulatory policy, and economic 

23 opportunity that govern interactions throughout the grid also guide the evolution of grid 

24 architectures. 

25

26 While early grids were similar in a broad enough range of characteristics that they could 

generally be described by a single architecture,6 27 today’s environment is far more 

28 heterogeneous. Vertically integrated utilities with conventional tariff structures remain the 

29 standard for large portions of the country, whereas other regions have embraced diversified 

asset ownership, 30 7 market-driven operations, and unconventional or non-wires alternatives to 

31 traditional electricity supply [37]. 

32

33 This Framework uses multiple grid architectures described by the U.S. Department of Energy 

34 (DOE) [38] as inspiration for use cases to explore the different types of interactions one 

35 could expect to see in the electrical grid. No single architecture is deemed the correct 

36 architecture, and the use cases employed herein are abstractions of the detailed DOE 

37 architecture descriptions intended to elucidate specific system characteristics.

38

39

40

41

6 For example, vertically integrated utilities with conventional generation (e.g., steam cycle, hydropower, or reciprocating 

engine), and unidirectional power flows from generator to radial distribution networks that fed customers with similar 

characteristics.

7 For example, through distribution system operators (DSOs) [36].
9

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1 1.3.2. Updated models

2

3 The NIST Smart Grid Conceptual Model is used to build a high-level and scalable 

4 understanding of the different physical and informational interfaces across the smart grid. In 

5 this Framework the Conceptual Model is updated to reflect evolving interface trends across 

6 the grid. The logical model of legacy systems from the previous Framework has been 

7 updated to explore interface characteristics across multiple grid architectures. 

8

9 1.3.3. A common language for the grid

10

11 Diversifying architectures complicates an already challenging space. As roles, 

12 responsibilities, and interfaces evolve across architectures, opportunities for 

13 miscommunication increase significantly — especially as companies engage in multiple 

14 locations and similar equipment is utilized in substantially different architectures. 

15

16 Interoperability depends on a consistent understanding of the language used to describe 

17 capabilities and requirements for devices, systems, and actors. To facilitate this common 

18 understanding of the language of the grid, NIST has applied a cyber-physical systems 

19 ontology [39] to the smart grid.

20

21 1.3.4. Tools to facilitate interoperability

22

23 Achieving interoperability is a complex challenge towards which compliance to individual 

24 communications or data model standards will yield limited progress. To maximize the 

25 benefits new devices and systems can bring to the electrical grid, NIST has developed an 

26 approach to interoperability that depends on co-optimization of standards requirements 

27 related to the physical function, communications protocols, and information models. 

28

29 Referred to as an interoperability profile, this approach to coordinated application of 

30 requirements which may span multiple standards is described. 

31

32 1.4. Use of this Framework

33

34 The results of NIST’s ongoing technical work reflected in this Framework document should 

35 assist smart grid stakeholders in future decision making. The ideas expressed in this work 

36 are foundational to information exchange and interoperability concerns across the smart grid, 

37 have gone through a full vetting process, and are expected to stand the “test of time” as the 

38 building blocks for emerging power sector issues. 

39

40 It is important to note that standards for electrical grid technologies are not static—as 

41 technology evolves, so too will the relevant standards. Standards undergo continuing 

42 revisions to add new functionalities, integrate with legacy standards, harmonize/align with 

43 overlapping standards, and remedy shortcomings that are discovered as their 

44 implementations undergo interoperability testing. Standards are also deprecated when no 

45 longer useful. The concepts and gaps described in this Framework provide a foundation to 

46 guide this process moving forward.
10

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1

2 Models for the Smart Grid

3

4 Several models have been developed by NIST to describe interoperability concerns in the 

5 smart grid. In this version of the Framework, these models are updated and expanded to 

6 reflect emerging power system trends. An ontology for the smart grid is also described, 

7 which can be used to model functional and requirements descriptions for actors and 

8 equipment across the grid. 

9

10 2.1. NIST Smart Grid Conceptual Model

11

12 The NIST Smart Grid Conceptual Model describes the overall composition of electric grid 

13 systems and applications. It is meant to provide a high-level view of the system that can be 

14 understood by many stakeholders. Originally introduced in 2010 [33], the Conceptual Model 

15 is updated with each Framework revision. The Smart Grid Conceptual Model update in this 

16 document (see Figure 4) reflects large increases in the number and types of distributed 

17 energy resources (DERs) used throughout the grid, the increasing importance and automation 

18 of distribution systems, new customer interactions and assets, and the role of service 

19 providers in the distribution system.

Key Messages – Models for the Smart Grid

Models aid our understanding of interoperability and other smart grid concerns, and facilitate 

common language and communication across stakeholders. Evolution in technology and grid 

architecture in recent years requires an update of these tools.

The NIST Smart Grid Conceptual Model reflects technology and platform-driven capabilities 

emerging in the Customer and Distribution Domains, as well as the structural reorganization 

of a system that is more reliant on distributed resources.

Communication Pathways Scenarios are presented to help stakeholders examine how 

interface requirements might change with different system architectures or control strategies. 

These scenarios are not mutually exclusive and allow users to visually examine 

interoperability considerations that might arise through decisions on technology, operations, 

or economic structure. 

Communications challenges increase with grid complexity, which adds risk to everything 

from stakeholder engagement to equipment procurement. An ontology for the smart grid is 

introduced to provide reference language that can be used to clarify communications.
11

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1

2 Figure 4 – Updated NIST smart grid conceptual model

3 The key Framework concepts derived from the updated Conceptual Model remain broadly 

4 similar to those of previous editions. First, the roles and responsibilities for actors and 

5 equipment in the electrical grid are a function of the domain in which they are applied. 

6 Through this lens we understand that functions required of grid equipment will likely change 

depending on the grid context, or domain, in which it is used.8 7 Benefits associated with 

8 equipment, resource, or action will similarly vary with domain and other context.

9

10 Second, the Conceptual Model reinforces the contrast between the growing complexity of 

11 information exchange necessary to operate the grid, and the relatively straightforward 

12 physical exchanges of energy that actually are the grid. Producing or consuming electricity 

13 still relies on relatively few and simply physical connections, even as energy technologies 

14 diversify across the system and grid dynamics become less certain. Conversely, grid 

15 communications and data complexity are exploding as people leverage the proliferation of 

16 low-cost power electronics, sensors, and microchips to support grid operations through 

17 coordinated actions of small-scale and distributed devices—coordination that was once the 

8 For example, a photovoltaic system installed at a single-family house may have significantly different operating 

parameters than ones installed at commercial facilities or used for bulk power generation.
12

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exclusive purview of large generators in close proximity.9 1 Whether to expand coordination 

of the high voltage system10 or to prolong the life of existing distribution infrastructure,11 2

3 information flows are increasing everywhere across the grid.

4

5 2.1.1. Conceptual model updates

6

7 While the high-level concepts contained in the NIST Smart Grid Conceptual Model have 

8 proven robust with time, the grid is also changing rapidly. The Conceptual Model and its 

9 derivatives have been updated to reflect many changes throughout the system and explore the 

10 associated impact on system interoperability requirements. These changes include:

11

12 Generation Domain

13 Changing scale — the domain name has been updated to Generation including 

14 DER to explicitly acknowledge the growing diversity in scale and utilization of 

15 grid resources.

16 Technology diversity — the number and types of generation technologies has 

17 been expanded, to reflect the growing diversity of U.S. generation assets [7].

18 Physical siting — the Generation including DER domain has been elongated to 

19 represent the geographic and topological diversity of included technologies. 

20 Icons representing large scale generation technologies are physically closer to the 

21 Transmission domain, and smaller scale or more modular technologies are 

22 physically closer to the Distribution and Customer domains.

23 Customer participation — resources provided by the customer, whether 

24 generation or demand management, are included as one of the many resource 

25 options available in the Generation including DER domain (see Figure 31).

26

27 Distribution Domain

28 Expanding role — the Distribution Domain has been made larger and placed 

29 more centrally within the Conceptual Model to reflect the growing responsibilities 

30 distribution systems have for optimizing grid function.

31 Improved sensing — sensing in distribution systems (represented by the icon of 

32 an overhead line fault detection device) is important to improving state awareness, 

33 a prerequisite for optimizing grid function.

34 Controllability and intelligence — computer servers represent the growing 

35 availability and use of real-time data for intelligent control of distribution grids.

36 New actors — historically the province of distribution utilities, service providers 

37 and other actors are increasingly providing equipment to and services for the 

9 For example, while energy imbalances between supply and demand used to only be managed by dispatching one of two 

large generators, today the same imbalance could also be addressed through the coordinated actions of many customers and 

their devices.

10 For example, the Western Energy Imbalance Market [40] 11 For example, the Brooklyn Queens Demand Management Project [37]
13

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1 distribution grid as indicated by the new link between the Distribution and Service 

2 Provider Domains.

3 Customer Domain

4 Distributed operations — with active energy management possible at the grid 

5 edge, operations, control and automation enter the customer domain as 

6 represented by the computer monitor replicated from the Operations Domain.

7 Customer diversification — from multi-family dwellings to commercial and 

8 industrial facilities and campuses, the Customer Domain has been updated to 

9 reflect many types of customers served by and interacting with the electrical grid 

10 and energy markets.

11

12 Even with these updates, the high-level Conceptual Model shown in Figure 4 is useful only 

13 for exploring the electrical and communications flows between grid domains. Much 

14 innovation occurs within the grid domains, the exploration of which improves understanding 

15 of the relationships between technology, communications, and interoperability. The 

16 Conceptual Model therefore includes detailed domain-specific examinations of smart grid 

17 roles, technologies, services, and information exchange, which are described in Section 2.1.2

18 and Appendix A – Smart Grid Conceptual Model Domains. 

19

20 Underlying the Conceptual Model is a legal and regulatory framework that governs many 

21 aspects of the electrical grid. These regulations apply to actors and applications, and to their 

22 interactions, throughout the system and enable the implementation and management of 

23 policies and requirements that keep the power system safe, reliable, and cost effective while 

24 maximizing the public good. Organizations that adopt these regulations exist at several 

25 levels, from federal agencies to public utility commissions at the state and local levels. 

26

27 The transition to a modern grid introduces new regulatory considerations, which may 

28 transcend jurisdictional boundaries and require increased coordination among federal, state, 

29 and local lawmakers and regulators. The Conceptual Model is intended to be a useful tool 

30 for regulators at all levels to assess how best to achieve public policy goals that, along with 

31 business objectives, motivate investments in modernizing the nation’s electric power 

32 infrastructure. 

33

34 2.1.2. Conceptual model domains

35

36 Each domain — and its sub-domains — in the Conceptual Model describe smart grid 

37 conceptual roles and services. They include types of services, interactions, and stakeholders 

38 that make decisions and exchange information necessary for performing tasks to achieve 

39 system goals, such as: customer and demand response management, distributed generation 

40 aggregation, and outage management. Services are performed by one or more roles within a 

41 domain. For example, corresponding services may include home automation, distributed 

42 energy resource (DER) and customer demand response, load control, and wide-area 

43 situational awareness (WASA).

44

45 Each of the seven NIST Smart Grid Conceptual Model domains is described in Table 1.
14

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1 Table 1 – Domains and roles/services in the smart grid conceptual model

Domain Roles/Services in the Domain

1 Customer The end users of electricity. May also generate, store, and manage 

the use of energy. Traditionally, three customer types are discussed, 

each with its own sub-domain: residential, commercial, and 

industrial.

2 Markets The facilitators and participants in electricity markets and other 

economic mechanisms used to drive action and optimize system 

outcomes.

3 Service 

Provider

The organizations providing services to electrical customers and to 

utilities.

4 Operations The managers of the movement of electricity.

5 Generation 

Including DER

The producers of electricity. May also store energy for later 

distribution. This domain includes traditional generation sources 

and distributed energy resources (DER). At a logical level, 

“generation” includes those traditional larger scale technologies 

usually attached to the transmission system, such as conventional 

thermal generation, large-scale hydro generation, and utility-scale 

renewable installations usually attached to transmission. DER is 

associated with generation, storage, and demand response provided 

in the customer and distribution domains, and with service 

provider-aggregated energy resources.

6 Transmission The carriers of high voltage electricity over long distances. May 

also store and generate electricity.

7 Distribution The distributors of electricity to and from customers. May also 

store

and generate electricity.

2

3

4 To enable smart grid functionality, the roles in a particular domain often interact with roles in 

5 other domains, as shown in Figure 4. Moreover, as system complexity increases and 

6 communications and interoperability expand operational control beyond the locational 

7 specificity of physical connections, it is likely that organizations will contain components of 

8 multiple domains. For example, the Independent System Operators (ISOs) and Regional 

9 Transmission Organizations (RTOs) in North America have roles in both the markets and 

10 operations domains. Similarly, a distribution utility is not entirely contained within the 

11 distribution domain—it is likely to contain roles in the operations domain, and perhaps also 

12 the markets domain as economic signals become more dynamic across the system. Vertically 

13 integrated utilities will have roles in many domains.

14

15 Detailed descriptions and diagrams for each of the NIST Conceptual Model Domains are 

16 provided in Appendix A – Smart Grid Conceptual Model Domains.
15

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1 2.2. Communication Pathways Scenarios

2

3 The updated Smart Grid Conceptual Model provides a high-level set of descriptions adequate 

4 to include the broad set of evolving trends in the smart grid. Yet interoperability 

5 requirements derive from specific system and device interfaces that are not sufficiently 

6 characterized by such high-level depictions. In this section, another set of model diagrams 

7 — communication pathways diagrams — are provided wherein the domain structure of the 

8 Conceptual Model is used to facilitate a more detailed examination of system interfaces.

9

10 The Communication Pathways Scenario diagrams are an update and diversification of earlier 

11 mappings drawn to provide a visual reference for legacy applications and logical interfaces 

12 within the context of the Conceptual Model. Published in earlier Frameworks, the legacy 

13 applications mappings depicted an overarching architecture and provided a static perspective 

14 on the range of system and device interfaces. Building on the emerging diversity of grid 

15 architectures and associated system interfaces, the logical application model drawing has 

16 been updated into a series of Communication Pathways Scenario diagrams to depict specific 

17 interfaces and conceptual issues inspired by the DOE’s reference grid architectures (see 

18 Section 1.3.1).

19

20 The architecturally inspired scenarios include:

21 • Legacy Communication Pathways Scenario

22 • High-DER Communication Pathways Scenario

23 • Microgrid Communication Pathways Scenario

24 • Hybrid Communication Pathways Scenario

25

26 These scenarios are not mutually exclusive. Rather, they represent views of the grid 

27 emphasizing various aspects. For example, many actors such as smart meters and advanced 

28 distribution systems appear in multiple reference models. 

29

30 2.2.1. Graphic conventions

31

32 Each Communication Pathways Scenario diagram uses a common set of graphical 

33 conventions. For each diagram colored boxes represent Conceptual Model Domains (see 

34 Table 2), and symbols are used to define actors, gateways, communications paths, and 

35 networks (see Table 3).
16

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1 Table 2 – Domain descriptions and graphical color representation

Domain Domain Role/Service Color Code

Operations The managers of the movement of electricity. Blue

Markets The operators and participants in electricity markets i.e. Independent 

System Operators (ISOs), Regional Transmission Organizations 

(RTOs), and Distribution System Operators (DSOs).

Purple

Distribution The distributors of electricity to and from customers. Light Brown

Transmission The carriers of bulk electricity over long distances. Maroon

Generation Generators of electricity. Includes older generation sources such as coal 

and other carbon-based fuels, nuclear, hydro as well as distributed 

energy resources (DERs) such as wind and solar.

Plum

Customer Residential, commercial, and industrial entities that use, produce, or 

store energy and interact with utilities, aggregators, and markets.

Orange

Service 

Providers

Billing, Information Technology (IT), finance, procurement, regulatory 

and aggregation functions performed for electric grid stakeholders.

Green

2 

3 Table 3 – Communication pathways diagrams symbol descriptions

Symbol Name Description Symbol

Comm. Network A communication network carries analog and digital information 

from a physical location to other locations

Roles and Actors Roles comprise specific business activities and actors can perform 

multiple activities. 

Gateway Role Role that represents a border of the communication network.

Comms. Path A communications path shows the route that information flows 

within a Domain. 

Comms. Path 

Changes 

Owner/Domain

A communications path that shows the route that information flows 

between domains and in some cases between the owners of the 

information. 

4 

5 The complexity of some scenario diagrams demands a simplified approach to portraying 

6 certain interfaces. When a communication pathway would likely interact with all domain or 

7 sub-domain actors in a similar manner, one pathway is drawn that terminates at the (sub8 )domain boundary rather than cluttering the diagram with redundant individual 

9 communication pathways to each actor. Although prevalent in all scenarios, this technique is 

10 most evident in the High-DER Scenario through the simplified interactions of the operations 

11 sub-domains with the “Operational Enterprise Service Bus” actor, and also in the simplified 

12 interactions of the Internet with each of the domains in Figure 6.

13

14 2.2.2. The legacy communication pathways scenario

15

16 The Legacy Communication Pathways Scenario (see Figure 5) depicts the Conceptual 

17 Model mapping to the overarching electric grid architecture from the previous revision of the 

18 NIST Interoperability Framework [19]. It serves as a baseline mapping that also depicts a 

19 structure representative of current electric grid systems. Domains and sub-domains show 

20 logical groupings of systems and applications. For example, transmission systems such as an 

21 Energy Management System (EMS) are shown in the transmission operations sub-domain 

22 within the operations domain.
17

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1 The model also shows information flows and communications paths between systems. 

2 Communications paths describe interfaces where standards may be helpful in defining the 

3 required protocols and characteristics of information exchange, although the depiction in this 

4 diagram of any single communication pathway is not in-and-of-itself an indication that NIST 

5 supports standardization of that interface.

6

7 Sub-domains in the Legacy Scenario are shown to identify typical groupings within the 

8 utility business sector. The particular collection of elements (network, roles, actors, and 

gateway role) helps define a business12 or department13 9 in an illustrative fashion without 

10 being exhaustive.

11

12

13 Figure 5 – Legacy communication pathways scenario

14

15 2.2.3. High-DER communication pathways scenario

16

17 The High-DER Communication Pathways Scenario (see Figure 6) represents current and 

18 future grids with DERs providing large amounts of power. In the future, market management 

19 functionality may be performed at both the distribution and transmission levels, and market 

20 makers such as Distribution System Operators (DSOs) will need to optimize for both 

21 economic factors and reliability.

12 For example: RTO/ISO, Utility Provider, or Third-Party Provider 13 For example: Transmission Operations, Distribution Operations

Service Providers

Third-Party

Provider

Utility

Provider

Operations

RTO/ISO

Ops

Transmission

Ops

Distribution Ops

Distribution 

Transmission

Customer

Generation

Markets

Demand

Response

CIS

Energy

Services

Interface

Meter

Customer

Equipment

Appliances

Customer

EMS

Aggregator

Billing

ISO/RTO 

Participant

Energy

Market

Clearinghouse

Others

Thermostat

Plant Control 

System

Substation

Device Electric

Storage

Substation 

Controller

Retailer / 

Wholesaler

Home / Building

Manager

Premises 

Networks

Data

Collector

DMS

Generators

EMS

Internet /

e-Business

Service 

Integration

Wide Area

Networks Field Area

Networks

Substation

Integration Field

Device

Market

Services

Interface

Roles and Actors

Domain

Gateway Role

Network

Comms Path

Comms Path Changes Owner / Domain

Aggregator

Distribution

SCADA

Metering 

System

WAMS

Asset

Mgmt

MDMS

EMS

Internet /

e-Business

Transmission

SCADA

Retail 

Energy 

Provider

CIS

Billing

Service 

Integration

Service 

Integration

RTO

SCADA

Distributed Energy Resources

Electric

Storage

Distributed 

Generation

Electric

Storage

Electric

Vehicle

Distributed 

Generation

 

Source: NIST Smart Grid Framework 3.0, 2014
18

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1 As described in Section 1.1, large increases in the number of DERs have occurred and are 

2 now much more common in electric grids. Distributed energy technologies are therefore not 

3 a special class of generation assets, but a typical asset that can use power generation or 

4 demand response to participate in balancing supply and demand in the electrical grid. 

5 Accordingly, DER assets can reside in numerous domains with numerous operational 

6 strategies. Some examples include:

7

8 Utility-owned DER assets: These assets reside in the Generation Domain and 

9 prioritize supporting conventional markets and grid infrastructure. 

10

11 Customer-sited DER assets: These assets reside in the Customer Domain and may 

12 prioritize local or non-utility services or operational strategies over utility priorities. 

13 Although sited at the customer premises, these assets may be controlled by customers, 

14 third party aggregators, or utilities. 

15

16 The High-DER Scenario in Figure 6 depicts a paradigm where market signals can be sent 

17 over the Internet to both distribution utilities or DSOs and to customers who own DERs. In 

18 this way, non-utility assets can participate and respond to the same market or other economic 

19 incentives as conventional resources. 

20

21 The colocation of customer-sited resources and loads—including demand response—means 

22 non-utility DERs could provide multiple services traditionally delivered through utilityowned assets.14 23 Importantly, the internet connectivity of DERs in this scenario means the 

24 device owner/operator could choose whether to optimize function around local concerns or 

25 those of a more regional or global nature.

26

27 Another important aspect of this model are the multiple communication pathways for many 

28 actors and gateways. While many communication pathways in these scenario diagrams are 

29 intended to aid in exploring the characteristics of specific interfaces, the diversity of 

30 interfaces and control loops depicted in Figure 6 instead highlight the complexity of 

31 interfaces for single actors, and the possibility for multiple redundant communication loops 

32 to yield conflicting information. 

33

34 Other points of interest for the High-DER Scenario include combining the RTO/ISO Ops and 

35 Transmission Ops sub-domain functions from the Legacy Scenario into a combined 

36 Generation & Trans Ops sub-domain. This is done to highlight how market functions in the 

37 High-DER Scenario may operate at different levels with fewer restrictions than those of the 

Legacy Scenario RTO/ISO Ops grouping.15 38 

14 For example, DERs such as solar photovoltaic or demand response can reduce peak demand during the mid-part of the 

day while an energy storage asset can supply reactive power. 15 In the Legacy Scenario RTO/ISO Ops functions are limited to cross-region functions on the bulk power system. 
19

Figure 6 – High-DER communication pathways scenario
20

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1 For this model, the Gateway, Data Transfer, and IP SCADA Communications role is placed 

2 across the system operations, transmission, and distribution domains, as this aligns with 

3 actual deployment and operation. Similarly, the Cogeneration actor is placed across the

4 customer, distribution, and generation including DER domains because the scale and 

5 specifics of each cogeneration deployment will determine the physical and functional domain 

6 alignment.

7

8

9 2.2.4. Hybrid communication pathways scenario

10

11 The Hybrid Communication Pathways Scenario shown in Figure 7 is inspired by the 

reference model for distribution grid control in the 21st 12 century [41]. It depicts a high DER 

13 environment with centralized, distributed (non-centralized) and edge functionality. Grid 

14 control devices are in the Transmission and Distribution Domains. This diagram is called the 

15 Hybrid Communication Pathways Scenario because it depicts a hybrid approach to 

16 operational communications that uses both public and private communication pathways.

17

18 This diagram depicts several concepts worth noting. The first is that each domain has its 

19 own edge, so the term grid-edge device immediately becomes context specific. For example, 

20 while a customer’s grid-edge device may be an appliance that actively manages energy 

21 consumption, the edge of a distribution utility’s grid is the smart meter behind which the 

22 entire customer domain resides. Further, the edge of the transmission grid may be the phasor 

23 measurement unit or intelligent electronic device positioned at a substation behind which 

24 exist the entire distribution and customer domains. This concept is also applied to distributed 

25 assets which lie in between the centralized systems and edge devices. 

26

27 Another important concept in this diagram is one of parallel communications infrastructures. 

28 While the dedicated operational communications network and pathways between the 

29 operations domain and actors in the distribution and transmission domain implies a 

30 proprietary communications infrastructure, unseen are the implied internet communications 

31 interfaces with each of the remaining actors in the scenario. While a DER, electric vehicle, 

32 or remote controllable appliance could be expected to be managed by a system operations 

33 domain actor in a high DER environment, it is not necessary that those operational 

34 communications utilize the same operational communications network as utility-owned 

35 critical infrastructure. 

36

37 A final concept worth noting is that market actors need not be classified as centralized 

38 infrastructure. While the classic model of an aggregator may be to bundle distributed 

39 resources for sale into centralized markets [42], aggregators can work in decentralized or 

40 local markets as can other market actors.
21

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1 

2

3 Figure 7 – Hybrid communication pathways scenario

4

5 2.2.5. Microgrid communication pathways scenario

6

7 Microgrids vary in scope ranging from a single premise to those including substations. 

8 Ownership and control of microgrids varies, with some owned and operated by consumers 

9 and some controlled by utilities that may or may not also own the microgrid. The Microgrid 

10 Communication Pathways Scenario depicts two example microgrids, one managed and 

11 controlled by a customer, and one managed by a utility.

12

13 Microgrids have the ability to isolate the circuits under their control from the main electrical 

14 grid. Modern microgrids can also be optimized to support overall grid health or provide 

15 specific grid services when operating while connected to the main electrical grid. Although 

16 managed by different entities, both types of microgrids are used primarily to improve 

17 reliability. In particular, microgrids are often deployed in situations where mission critical 

18 functions require power to be available at all times.

19

20 The principal difference between the customer- and utility-managed microgrids is in 

21 determining which communication pathways change domains and/or transition between 

22 assets with different owners. Communication pathways that change owner or domain —

23 colored brown in Figure 8 — are more likely to benefit from interoperability standardization.
22

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1

2 Figure 8 – Microgrid communication pathways scenario

3

4 2.3. An Ontology for the Smart Grid

5

6 The electrical grid is an impossibly large and complex system that has been called the 

greatest engineering achievement of the 20th 7 century [43]. Beyond the sheer scale of the 

8 infrastructure, electrical grids are complex systems of systems (SoS) in which mechanical, 

9 electro-mechanical, and electronic control devices must all work together in near-real time 

10 with human oversight and intervention to produce and manage the electricity critical to 

11 modern society [3]. 

12

13 And yet despite this complexity, the language we use to describe the grid is often obtuse and 

14 lacks the clarity necessary to describe the specific capabilities that enable a complex SoS to 

operate.16 15 Even the term interoperability belies the complex series of interactions and 

16 requirements necessary to exchange actionable information (see Section 6 –Testing and 

17 Certification). 

18

19 A common understanding of the relationship between individual component capabilities and 

20 the functions of the broader electrical system could improve our ability to communicate 

21 between stakeholder groups regarding objectives, concerns, and strategies for grid 

modernization. Yet any pursuit of a common set of terms, or ontology,17 22 for the electrical 

23 grid must address the fact that the grid is not an isolated system. Indeed, electricity is the 

24 preferred energy carrier for modern society, and as a key enabling critical infrastructure the 

16 For example, popular media will use catch-all phrases like “intelligent grid” [44] to describe any number of complex 

interactions and developing system capabilities, and the term “grid modernization” on the regulatory arena can mean 

anything from advanced metering to utility business model reform to microgrids and demand response [45]. 17 An ontology is a set of concepts and categories in a subject area or domain that shows their properties and the relations 

between them [46].
23

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1 grid serves a great number of other systems — including many that are life-critical [16]. The 

2 electrical grid is therefore but one domain in the broader universe of cyber-physical systems.

3

4 Current design and management approaches for these broader systems are often domain5 specific, resulting in redundant efforts that lack the robust, formal methods for design, 

6 evaluation, verification, and validation. Any ontology developed for the electrical grid 

7 should be consistent with those ontologies already developed for other cyber-physical 

8 systems; doing so would improve interactions and enable co-optimization of the grid with the 

9 other systems it serves.

10

11

12 2.3.1. The NIST framework for cyber-physical systems

13

14 Relying on engineered interactions between physical and computational components also 

15 means the electrical grid is a cyber-physical system, and because the grid only works when 

numerous systems operate in parallel18 16 the electrical grid is actually a multi-layered cyber17 physical SoS. The design and engineering of advanced cyber-physical systems such as the 

18 smart grid can be so complex that existing approaches for performance prediction, 

19 measurement, management, and assurance are often inadequate.

20

21 NIST’s Framework for Cyber-Physical Systems [39] provides a useful analysis methodology 

22 and template for developing ontologies to describe key features of cyber-physical systems 

23 (CPS). Facets and Aspects are core concepts to this methodology.

24

25 Facets are inclusive of all system engineering processes (conceptualization, 

26 realization, and assurance), and can be thought of as “modes of thinking” about a 

27 CPS.

28

29 Aspects are groupings of stakeholder concerns along functional, business, human, 

30 trustworthiness, timing, data, composition, boundaries, and lifecycle concerns. 

31

32 As seen in Figure 9, the CPS Framework’s methodology provides holistic concern-driven 

33 input to guide the development of the set of activities and artifacts, regardless of the specific 

34 systems engineering approach used. In this implementation, the Domains represent different 

application areas of CPS,19 35 including smart grid (Energy).

18 For example, the transmission SoS is operated in parallel to the distribution system, which is also a SoS whose 

components include system operators, switches, distribution lines, and advanced inverters.

19 The logical relationship between the “domains” in Figure 9 and the Smart Grid Conceptual Model domains which 

describe roles and services within the grid is that changing the CPS application domain (e.g., from energy to healthcare) 

fundamentally alters participant roles and procured services within that system, just as the Distribution to the Markets 

domains of the Smart Grid Conceptual model have different participant roles and procured services.
24

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1

2 Figure 9 – CPS framework domains, facets, and aspects

3 2.3.2. The aspects of a modern electrical grid

4

5 An electrical grid is an energy-domain application of a CPS, so the aspects of a CPS shown 

6 in Figure 9 also apply to the grid. A modernized electrical grid aligns to the cyber-physical 

7 framework’s aspects as follows:

8

9 Functional — Concerns about function, including sensing, actuation, control, 

10 and communications, accurately describe grid modernization issues. For 

11 example, one grid modernization functional aspect concern relates to the 

12 impact that incorporating DERs on electrical distribution grids will have on 

13 the sensing, control, and communications requirements of existing systems.

14

15 Business — Concerns about enterprise, time to market, environment, 

16 regulation, cost, and other business areas. For the electric grid, a key business 

17 aspect concern involves the ability to design markets to optimize energy costs 

18 as many locations transition from regulated monopoly markets.

19

20 Human — Concerns about human interaction with and as part of a CPS. An 

21 important human aspect concern is whether human-in-the-loop system 

22 operators will be able to effectively manage a grid with potentially millions of 

23 new distributed generation devices not under their direct control.

24

25 Trustworthiness — Concerns about trustworthiness of CPS including 

26 security (cybersecurity and physical security), privacy, safety, reliability, and 

27 resilience. Addressing these concerns, including understanding and managing 

28 their interrelationships, is fundamental to the electric grid. Thus the 

29 trustworthiness aspect should be considered as a key driver for grid 

30 modernization, including through its impact on development of grid 

31 architectural principles.
25

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1 Timing — Concerns about time and frequency signals, including the 

2 generation and transport of time and frequency signals, timestamping, 

3 managing latency, and timing composability. Timing aspect concerns reflect 

4 the real-time nature of electricity generation, transmission, distribution, and 

5 use, and have long been addressed by the electric industry through many 

existing electrical grid timing standards.20 6

7

8 Data — Concerns about data interoperability including fusion (situational 

9 awareness), data definitions (metadata), privacy, quality, type, and identity. 

10 Data interoperability is a key concern of the electric grid as evidenced by 

11 international standards such as IEC-61850 which defines configuration data 

12 for electric substation Intelligent Electronic Devices (IEDs). In addition, data 

13 accuracy, timeliness, and availability are crucial to data analytics ability to 

14 improve grid operation. 

15

16 Boundaries — Concerns related to topological, functional, and organizational 

17 demarcations and interactions. For electrical utilities, a persistent boundary 

18 aspect concern is the friction between organizational siloes that must be 

19 integrated in order to maximize the operational efficiency of the grid. 

20 Examples include the boundaries between Information Technology (IT) and 

21 Operational Technology (OT) organization groups.

22

23 Composition — Concerns related to the ability to construct new systems from 

24 existing CPS systems. For electrical utilities, a current composability concern 

25 is how to effectively replace newly constructed control systems that combine 

26 Outage Management System (OMS) and Distribution Management System 

27 (DMS) features. Another key composition aspect concern is the ability to 

28 integrate utility control systems with user-owned and controlled DER assets.

29

30 Lifecycle — Concerns related to the management and maintenance of CPS 

31 systems and components throughout their lifecycle, including design, 

32 deployment, operation, enhancement, and ultimately disposal. For electrical 

33 utilities, lifecycle concerns include the need to maintain system and 

34 component performance time periods as expectations of system lifetimes are 

often measured in decades rather than years.21 35 Another lifecycle concern is 

36 the need to manage increased repetitive usage of grid control devices such as 

37 tap changes which may need to operate much more frequently to control 

38 voltage changes induced by modern loads and distributed generation. A 

39 further lifecycle aspect concern is how to upgrade firmware in existing 

40 devices to support new features such as the ability of advanced inverters to 

41 control voltage and frequency.

20 For example, IEEE 1588-2008 Standard for a Precision Clock Synchronization Protocol for Networked Measurement and 

Control Systems [47] 21 The average age of power plants is over 30 years [48].
26

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1 2.3.3. Aspects and concerns of the electrical grid

2

3 The CPS Framework “aspects” and “concerns” apply to all cyber-physical domains and can 

4 be mapped to a modern electric grid. The first step in this mapping is to evaluate the grid 

5 context for the existing set of CPS concerns, and if necessary to clarify the description of the 

6 CPS concern in the context of the electric grid. The results of this exercise are presented in

7 Table 14 of Appendix B – Mapping CPS Aspects and Concerns to the Electrical Grid. CPS 

8 concerns relate directly to system performance, and the domain-driven context for these 

9 concerns characterizes the relationship between the concern and system function. 

10

11 The relationships between these concepts form the basis of a system ontology. In Table 14, 

12 the “Architecture Significance” column provides some examples of how each concern relates 

13 to activities or emerging trends in power systems as well as changes that could arise as new 

14 architectures are introduced. The architecture significance column therefore may help clarify 

15 the importance of CPS concerns to the electrical grids of today and tomorrow.
27

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1

2 3 Operations

3

4 [The Framework shall be] designed to accommodate traditional, centralized

5 generation and transmission resources and consumer distributed resources,

6 including distributed generation, renewable generation, energy storage, energy 

7 efficiency, and demand response and enabling devices and systems.

8 Energy Independence and Security Act of 2007

9

10 Electric power systems serve populations spanning communities, nations, and even 

11 continents. They are naturally complex due to the large number of physical connections 

12 whose states are determined through a combination of individual choices, environmental 

13 conditions, the status of neighboring connections, and even the unknowable. Indeed, it is 

14 impossible to know all aspects of a complex system at any one time, and this is especially 

15 true for the electrical grid [49]. Yet the system functions despite this complexity, and over 

Key Messages – Operations

The use of open standards to achieve interoperability is key to optimizing utility operations as 

new devices, systems, equipment, and technologies are increasingly used within the context of 

an aging electric grid.

Customers will expand their participation in grid operations and control schemes, both 

obtaining additional value from and contributing new resources to the system.

The ongoing transition from analog to digital energy technologies alters the physical dynamics 

at the edge of the system and has implications for operations. This emerging physical context 

affects system observability requirements and operational schemes, meaning issues of physical 

interoperability require attention as a complement to the traditional concerns of informational 

interoperability.

Interoperability is a principal enabler of system control schemes that can manage and rely on 

the active participation of distributed resources while empowering customers to provide 

solutions across numerous scales. Operational trustworthiness emerges as a requirement for 

grid modernization.

Interoperability allows utilities, system operators, and other grid participants to select and 

implement high-priority capabilities from a menu of available operational strategies. 

Customer-focused and utility-centric control strategies are therefore no longer mutually 

exclusive.
28

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1 time several strategies have emerged which allow the grid to be operated in a deterministic 

2 manner.

3

4 Chief among the strategies to simplify operations was averaging uncertainties within the 

5 system. At the turn of the last century when Samuel Insull electrified Chicago, he did so by 

6 building ever-larger generators and incorporating more neighborhoods into the utility’s 

7 service territory in a virtuous cycle of physical and economic efficiency [50]. Ancillary 

8 benefits to Insull’s economic efficiencies include physical momentum provided to the grid by 

9 thousands of pounds of spinning steel in each large-scale generator, and a smooth electricity 

10 demand curve determined by the collective behavior of millions [16]. Expansive service 

11 territories and physically imposing generators mask grid complexity by averaging out and 

12 riding-through physical uncertainty within the system, thereby making operation of large13 scale electrical systems tractable. 

14

15 As technology and regulatory policy have evolved, so too have the constraints within which 

16 the grid must be optimized. From 1978 onward, public policy in the United States has 

17 required utilities to purchase electricity from the most economically efficient producers [51]. 

18 This altered the financial calculus for investing in large-scale generators, as did emerging 

19 innovations in thermal cycle and energy conversion technologies that could yield similar or 

20 higher energy production efficiencies with smaller-scale and modular technologies and 

21 investments. As energy technologies migrate toward efficiency models governed by 

semiconductors22 and information technology,23 22 the forces of technological change driving 

23 technology towards the edge of the system are similarly driving change in the strategy for —

24 and structure of — utility operations [52].

25

26 Even as information exchange becomes an increasingly critical part of the electrical grid, our 

27 ability to quantify interoperability and its operational impacts remains limited. The challenge 

28 of quantifying interoperability benefits is well documented [53], and indeed our own 

definition of interoperability is functional in nature (see Section 1.2)24 29 and cannot be 

30 characterized with a static metric or measurand. Understanding the evolving role 

31 interoperability has in smart grid operations therefore requires examining a range of 

32 functional contexts. It is from these functional contexts that it becomes possible to 

33 characterize the importance of, and future requirements for, the exchange and use of 

34 information across the grid.

22 The efficiency of a solid-state transformer or inverter is governed by semiconductor switching, battery storage efficiency 

is governed by chemistry at the electrode, and photovoltaic efficiency is governed at the photonic scale.

23 Exchange of operational information allows for regular and more efficient redispatch of system resources [52]. 24 Earlier in this report we define interoperability as the capability of two or more networks, systems, devices, applications, 

or components to work together, and to exchange and readily use information.
29

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1 3.1 Interoperability for Utilities

2

3 3.1.1 System composition and constructivity

4

5 Expanded use of DERs and other new technologies, as described in the communication 

6 pathways scenarios (see Section 1), will have impacts throughout the electricity system —

7 including the Bulk Power System — and require utilities to integrate more refined 

8 observation and control at the edge of their respective systems [54]. But even without 

9 technology advancement, product lifecycles and evolving safety requirements [55] demand 

10 integration of new devices and systems into the existing grid. Utilities therefore cannot 

11 escape the challenge of integrating new equipment into their existing systems, which 

12 typically involves significant effort and expense [22]. 

13

14 In 2016 the DOE described the lessons learned from nearly $8 billion in public and private 

15 smart grid investments. While a majority of these funds ($4.4 billion) supported advanced 

16 metering infrastructure (AMI) deployment, significant investments were also made in 

17 distribution grids ($2.2 billion), customer systems ($0.8 billion), and the transmission system 

18 ($0.5 billion). The DOE concluded that integration of new and legacy systems was a 

19 constant challenge for nearly all utilities, and that turnkey solutions for these integration 

20 issues were generally not available. The Department also noted that customized testing, 

21 coding, and systems development was often required to achieve the interoperability 

22 necessary for utility operations [56]. 

23

24 Although specific interoperability costs and value metrics are difficult to quantify, utilities 

25 and equipment manufacturers have reported to NIST that their costs for integrating non26 interoperable equipment and systems ranges from $140 million to $1 billion per year per firm 

27 [23]. The scale of these outlays indicates an interoperability value proposition that could 

28 exceed even the upper estimates of $10 billion in interoperability-derived annual savings [26]

29 that is potentially achievable in the U.S. electric power industry.

30

31 The savings described above are for point-to-point system integration [22], which are similar 

32 in form to the interoperability challenges faced when a utility interconnects new and legacy 

33 systems through back-end integration, or when a utility tries to integrate power system 

components of various types and configurations into a common system.25 34 Standards-based 

35 interoperability approaches have been identified as a key opportunity to mitigate these costs 

36 [22, 53].

25 This concern is called “constructivity” in the ontology of the smart grid (see Appendix B – Mapping CPS Aspects and 

Concerns to the Electrical Grid).
30

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1 3.1.2 Hedging against obsolescence

2

The electric grid is aging. From generators26 to transformers and other parts of the system,27 3

4 a substantial portion of grid assets have either reached the end of their planned lifetimes or 

5 are technically obsolete [58]. Additionally, research has suggested the challenges and costs 

6 of dealing with the aging of smaller commodity units that make up the majority of the 

7 electrical grid might be substantially higher than those associated with the major equipment 

8 classifications described above [59].

9

10 Aging infrastructure presents a particularly challenging task to the electric utility: how to 

11 manage grid assets which have reached the end of their designed operating life but are still in 

12 use. These aged but functional assets were specified decades earlier for a likely very 

13 different grid and set of operating conditions. Equipment which achieves longer-than14 planned functionality also tends to be over-specified for the original task [59], and it is up to 

15 the utility to determine if these technically obsolete — but still functional — assets bring 

16 enough value to the system to warrant the ongoing investment necessary to extend their 

17 functional and economic lifetimes.

18

19 Informational requirements in the smart grid era compound the challenge of extending asset 

20 lifetimes, as the functionality of modern equipment is often inextricably linked with its 

21 ability to communicate with the broader system. The task of interfacing information 

22 technology systems from different eras can quickly become an exercise in developing custom 

23 interfaces — physical and informational — and the over-specificity of decades past which 

24 allowed the device to operate longer than anticipated may also inhibit efforts to adapt device 

25 communications to anything beyond the originally intended function and interface.

26

27 It is well known that standards-based interoperability requirements are key to maximizing 

28 equipment capabilities in the smart grid [21], and to reducing the effort and expense of 

29 integrating new equipment into legacy systems [22]. Given the extensive availability of 

30 standards for mapping between communications protocols and/or information models [60], 

deriving today’s interoperability specifications from open standards 31 28 may give firms the 

32 opportunity of easily mapping these specifications to future standards as smart grid 

33 equipment and informational requirements evolve. In essence, adopting open standards 

34 avoids over-specification of information technology requirements and is a mechanism for 

35 utilities to hedge against the limitations and expenses inherent in developing customized 

36 interfaces required for lifecycle extensions of assets that would otherwise become obsolete.

26 More than 6,000 generators representing 35 percent of all grid-tied generating capacity are more than 40 years old [15]. 27 Seventy percent of power transformers and transmission lines are more than 25 years old, and 60 percent of circuit 

breakers are more than 30 years old [57]. 28 Open standards are nonproprietary and involve a consensus-driven approach to establishing the requirements.
31

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1 3.2 Interoperability for New Technology

2

3 The number and types of technologies used throughout the power grid are evolving rapidly 

4 (see Section 1), with emerging system compositions upending many traditional operating 

5 strategies. Observations of power quality and other functional metrics [61] enabled by 

6 increasing sensor deployments [17] reveal an urgent need to improve our understanding of 

7 the emerging interactions between grid technology, equipment, and operations.

8

9 While it is clear the ongoing transition from analog circuitry to semiconductor technology 

10 throughout the grid will have some impact on the control schemes and waveforms of 

11 alternating current, the absence of historic observability for distribution system power quality 

12 means we do not know a priori whether new measurements are indicative of worsening 

13 system performance or merely reflect migration from functional states of years past which 

14 yielded similarly challenging—albeit unobserved—characteristics. These emerging datasets 

15 engender questions regarding the causes and long-term trends of the observed phenomena, 

16 and the implications for interoperability in future smart grids. 

17

18

19 3.2.1 Changing physics at the edge of the system

20

21 The electric grid emerged in an analog world, in which common circuit elements yielded 

22 smooth operational characteristics that in turn afforded substantial flexibility in system 

23 operations. In this early environment, the alternating current likely resembled a smooth 

sinusoidal waveform that could be used whether in its ideal form or not.29 24 The latter point is 

25 important because most analog electrical equipment continues functioning reasonably well 

26 even as grid conditions deviate from ideal, which has always provided some measure of 

27 operational flexibility. 

28

29 For example, the current-voltage relationship for an ideal resistor is a straight line. This 

30 simple characteristic means that by using Ohm’s law we can state that when circuit voltage 

increases, the power through a resistor increases in a smooth and quasi-linear30 31 fashion. 

32 Similarly, the power through a resistor decreases when circuit voltage decreases. The 

33 behavior is predictable, and the resistor still functions—albeit with slightly modified 

34 performance outputs—even as circuit conditions deviate from normal.

35

Incandescent lightbulb filaments are resistors,31 36 examination of which can aid our conceptual 

37 understanding of the relationship between the physics and operational flexibility of analog 

grids.32 38 When an incandescent bulb receives more or less voltage than intended, it will 

29 The term “likely” is inserted here because the metrology equipment necessary to observe waveform characteristics was 

not, at the time, deployed on the electric grid. 30 The relationship between voltage and power is not purely linear because power rises with the square of voltage. However, 

the relationship between voltage and power for analog circuits is a smooth function that can be approximated as a linear 

relationship for small voltage differentials. 

31 Although not an “ideal resistor,” under grid conditions lightbulb filaments are a useful proxy for the ideal resistor 

described in the previous paragraph.

32 Although the current-voltage-resistor relationship described by Ohm’s law applies to direct current electric circuits, purely 

resistive elements do not affect the phase of an alternating current circuit and so the direct current relationships described 

still apply, albeit with impedance substituted for resistance.
32

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1 simply glow more brightly or dimly than it would at the standard voltage rating. Indeed, this 

2 phenomenon is the basis for the term “brownout,” which occurs when utilities reduce the 

3 electrical voltage provided to customers (usually as part of emergency actions to match 

4 available supply and demand). The voltage reductions during brownouts reduce power 

5 consumption while still providing customers with some minimum level of electrical service, 

6 and the analog characteristics of the incandescent bulb continue to provide a reduced level of 

7 functionality under sub-optimal conditions.

8

9 Other analog circuit elements also have response characteristics that allow for continued use 

10 under sub-optimal conditions. Inductive motors, for example, can operate at suboptimal 

11 circuit voltages and frequency, albeit with reduced efficiency which may minimize device 

usefulness under degraded conditions.33 12 Yet inductive motors and loads are designed to 

13 continue operations through suboptimal grid conditions [62] and regularly do so.

14

15 The smooth physics of analog circuitry does not apply to modern semiconductor-based 

16 electronics. That the electrical conductivity of a semiconductor changes with environmental 

17 conditions is the very essence of that material class, and it is through control of these 

18 parameters via transistors that semiconductors become computationally powerful. The 

ability to precisely control conductivity in transistors34 19 is also what makes semiconductor20 based power electronics valuable to the electric grid.

21

22 Yet the binary nature and fast switching capabilities of transistors and diodes in 

23 semiconductor based (solid-state) power electronics introduce functional step-changes to 

24 normal operations which change the physical dynamics of the grid. While the benefits from 

25 high electrical efficiency and discrete controllability are immense, the very nature of this 

26 switching creates minute but very sharp step-changes in the aggregate waveform which can 

manifest as nonlinear and transient interactions35 27 with the rest of the system. 

28

29 As different as the strategies are for managing analog circuit elements (e.g., resistors, 

30 inductors, and capacitors), even more diverse are the integration requirements and 

31 operational strategies for managing semiconductor-based systems. Solid-state power 

32 electronics are scalable and modular, which provides meaningful opportunity to improve 

33 efficiency and control throughout the distribution system. This is especially true at the 

34 system edge where customer technologies are diversifying and gaining new energy 

35 management capabilities. Changes to grid physics associated with the transition from analog 

36 to digital (or solid-state) components warrants examination as stakeholders seek to 

37 understand evolving interoperability requirements for observing and controlling the grid.

33 Because of phase interactions between inductive loads and alternating current circuits, under highly stressed grid 

conditions it may be possible for motors or other inductive loads to contribute to system failure in a way that resistive loads 

do not. 

34 Diodes are also used in semiconductor-based electrical loads and can be designed to have switching characteristics similar 

to transistors, albeit with switching characteristics driven by voltage thresholds. However, transistors provide the optimal 

controllability. 

35 For example, simultaneous switching of large numbers of diodes can produce a current inrush which induces a magnetic 

field that can affect the impedance of the very wires through which that electricity is flowing [63].
33

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1 3.2.2 Changing supply and demand technology

2

3 The introduction of distributed generation is often cited as a prominent source of power 

4 quality issues in distribution grids [64-67]. It seems logical that a grid originally designed for 

5 unidirectional powerflows from centralized generating facilities outward could buckle under 

6 the stress of incorporating generation and active power management technologies at the 

7 customer site. As generation capabilities have changed, uncertainty over the impacts of these 

8 technologies has also emerged. 

9

10 Solar inverters provide an interesting case-study on the changing capabilities of generating 

11 technologies. In 2003 IEEE published standard 1547, the first grid interconnection standard 

12 for distributed resources. Most commonly applied to inverter-based generation, the evolution 

13 of this standard and inverter capabilities provides an interesting case-study in the accelerating 

14 evolution of technology on the grid. The original IEEE standard mandated just one actively 

15 controlled capability—the ability for distributed resources to de-energize (turn off) when grid 

16 voltages or frequencies deviated from a narrow operational range [68]. Just fifteen years 

17 later more than 35 new DER functions had been identified (see Appendix C – Inverter and 

18 DER Functions), some of which have become mandatory through California Rule 21 and the 

19 2018 revision of IEEE 1547. 

20

21 The confluence of dramatically expanding DER capabilities with grid management schemes 

22 that historically modeled customers as passive system loads [69] would seem to buttress the 

23 argument that distributed generation could be the primary source of power quality issues and 

24 emerging dynamics on the distribution grid. Yet distributed solar generation accounted for 

25 only 0.7 % of total U.S. generation in 2018 [70, 71], and so it is important to consider 

26 whether there may be other more ubiquitous causes for the emerging grid dynamics. 

27

28 Importantly, the transistors and diodes changing the physics of the power grid (see Section 

29 3.2.1) exist in all forms of solid-state power electronics, and not just inverters and other 

30 generation assets. Research has shown that the power electronics in CFL and LED lightbulbs 

31 can severely affect local electrical waveforms, a phenomenon which does not occur for 

32 incandescent bulbs. When combined with other circuit elements, including switches and/or 

33 dimmer controls, the distortions can appear extreme (see Figure 10, [72]).

34

35

36

37 Figure 10 – Example electrical waveform distortions observed in NIST experiments
34

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1 Considering the ubiquity of semiconductor-based power electronics in both existing 

technologies36 2 and emerging devices, the major driver affecting the declining power quality 

3 of our electric grids [73] may in fact be changes in how electricity is consumed rather than 

4 the oft-cited emergence of distributed generation. That grid performance can be materially 

5 affected by energy consumption comes as no surprise — after all, supply and demand has 

6 been balanced in real-time since the grid’s inception. It is, however, the emerging and 

uncontrolled interaction37 7 of modern devices with the grid through nontraditional physical 

mechanisms38 8 that demands a sharper focus on the physical aspects of system 

9 interoperability.

10

11 3.2.3 Alternating and direct current interactions

12

13 The revolution in solid-state power electronics described above has led to a proliferation of 

14 direct current (DC) devices and systems. More than just battery-driven electronics, DC 

equipment and appliances already permeate our homes and businesses39 15 and are becoming 

16 available for all manner of end-use applications [74]. 

17

18 The benefits of using DC systems in buildings include lower capital and installation costs, 

19 improved energy efficiency, and a reduced physical footprint which enables more flexible 

20 design. Combining DC building systems to utilize a common transformer or other DC power 

21 source would compound gains to yield dramatic efficiency improvements and simplify 

22 building design constraints [75], especially when DC energy sources such as solar PV or 

23 battery electric storage are available onsite. 

24

25 Expansion of DC technologies into applications and services traditionally served by 

26 alternating current (AC) technology can be extremely beneficial, as DC-ready appliances 

27 typically operate at or above the highest energy efficiency levels of their conventional AC 

28 counterparts [74] and provide greater functional controllability. Extensive DC technology 

29 deployment could also impact utility operations at the grid-edge and even limit the efficacy 

of traditional AC system management techniques,40 30 but may also alter customer service 

31 requirements and potentially allow utilities to relax their operational constraints.

32

33 Utility-scale distribution grids will continue AC operations even as the foothold for DC 

34 technology grows. Expanding use of DC technology in devices, systems, and even 

35 microgrids highlights the need to better understand the effects physical interoperability 

36 between DC and AC systems will have on control theory and operational practice.

36 For example: computers, televisions, mobile device chargers, and variable speed electric motors/fans, among others. 37 These interactions are not governed by a centralized dispatch or even an adaptable control algorithm, but instead by the 

fundamental characteristics of the energy consumption that are unique to each device or class of devices.

38 Not only can energy consumption introduce harmonic distortion to the local circuit, but distortion of the baseline supply 

waveform amplifies the device-introduced distortions [73]. This could create a feedback mechanism accelerating grid 

performance degradation and warrants further study.

39 Every computer, flat panel display, or device that has a rechargeable battery is a DC device. 40 Conservation Voltage Reduction (CVR) is one management technique that is rendered ineffective by DC devices and 

systems. Utilities employ CVR to reduce energy demand by lowering circuit voltage and corresponding power consumption 

through the relationship described in Section 3.2.1. However, the power electronics in most DC devices readily convert all 

manner of AC waveforms to the required DC voltage and current, and so would continue to function and consume energy 

normally and without adjustment during a CVR event. 
35

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1 Standards for DC systems and microgrids are only now emerging for modern energy 

2 applications, and will need to be developed further as these technologies penetrate the 

3 marketplace. 

4

5 3.2.4 Electric vehicles and a changing infrastructure

6

7 Sales of electric vehicles (EVs) in the United States increased 49% annually on average from 

8 2010-17, [76] and the more than 1 million electric vehicles on the road by the end of 2018 

9 are a major driver of change within the electric industry [77]. Although projections about 

10 future growth in EVs vary widely, even the more conservative growth estimates have 

11 implications for future grid operations, economics, and markets.

12

13 Growing electricity demand for vehicle charging will bring additional revenue to generators, 

14 system operators, and utilities alike, while also benefiting customers through reduced 

15 transportation fuel costs. But increased residential load from EV battery chargers will also 

16 require controlled/managed charging to mitigate potential peak load conditions on 

17 distribution transformers and feeders, while still providing owners with timely recharging 

18 capabilities.

19

20 Managed charging programs for EVs are offered by utilities and third-party service providers 

21 and successfully adjust peak loads to lessen infrastructure risks [78]. This can be 

22 accomplished through a variety of control schemes and communication mechanisms, 

23 including direct control (local or remote), rate design offerings, or through market signals. 

24

25 The data and communications requirements necessary to support managed charging and 

26 vehicle-to-grid interactions are being developed and standardized through an interoperability 

27 profile. For more on this topic, please see Section 6.

28

29

30 3.3 Evolving Control Schemes

31

32 Grid management techniques devised more than a century ago, and described earlier in this 

33 chapter, have worked admirably. But the change in grid economic systems over the past 

34 forty years, and the technological advancements which have occurred over the same 

35 timeframe, are changing how the system is controlled. Where averaging away complexity 

36 and uncertainty was originally a benefit that enabled scale, doing so today omits economic 

37 opportunity and diminishes the available solution space within which utilities can optimize 

38 their operations.

39

40 And so while the characteristics of the grid are changing in an uncertain way (see Section 

41 3.2.1), the mechanisms for controlling the grid and operating the grid are also evolving. The 

42 next two sections examine how different control schemes can affect organizational concepts 

43 and system interoperability requirements.
36

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1 3.3.1 Utility-driven control schemes

2

3 The modern electrical grid is managed through a series of physical operations and economic 

4 optimizations designed to keep the system running at greatest efficiency while minimizing 

5 the chance of disruption. These functions can be triggered through automated process, 

6 operator dispatch, or economic signal. The interoperability requirements associated with 

7 each operation will change with the temporal, spatial, and topological constraints for the 

8 function.

9

10 For the utility, architecture and operations need to accommodate both new and legacy 

11 devices in an evolving environment which is being rapidly influenced by policy and market 

12 decisions. Any of the dimensions mentioned above can be used to organize system function 

13 to aid our examination of the associated interoperability requirements. Below is an 

14 illustrative listing of some near- and medium-term grid functions that could be developed to 

15 mitigate some of the uncertainty and operational challenges emerging in the grid, grouped by 

16 implementation time-constant.

17

18 60Hz+ (sub-cycle) <5 minutes (sub-dispatch interval)

19 Real power stabilization Frequency regulation

20 Reactive power stabilization Local optimization

21 Power flow control Congestion management

22 Microgrid islanding

23 Dynamic distribution reconfiguration

24

25 5-15 minutes (linked to dispatch cycle) >15 minutes (intra-day and day 

26 ahead)

27 Dynamic line and transformer ratings Upstream Volt/VAR control 

28 Dynamic topology management Security-constrained unit commitment

29 Flexibility ramping

Forecast driven SCED41 30

31 Bulk power real-time redispatch

32 Real-time energy imbalance and settlement

33

34 Although not a comprehensive set of grid functions, the above listing is indicative of the 

35 diversity of functions and grid services that are or could soon be regularly provided across 

36 the system. Grouping along the temporal dimension provides an intuitive understanding of 

37 some interoperability requirements, such as data timeliness, and allows us to evaluate these 

38 functions in relation to conventional market structures. Other dimensions along which these 

functions must also be understood include topological,42 control mechanism,43 39 and 

economic,44 40 as each of these considerations drive a number of interoperability requirements.

41 Security Constrained Economic Dispatch 42 Will the service be provided in the bulk or distribution grids, or on the customer side of the meter? 43 Will the function be controlled through utility dispatch or automated algorithm? 44 Will the service value be determined by fixed tariff, market settlement, or some other dynamic approach?
37

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1 As we consider the above list of possible grid functions, it is clear that the majority of fast2 acting opportunities are at the edge of the system. A future grid state that could incorporate 

3 and benefit from these — or similar — capabilities will rely on innovation in resource 

4 flexibility, power electronics, distributed intelligence, and adaptive protection [54]. Changes 

5 of this magnitude will expand the awareness requirements for the distribution utility, which 

6 would benefit from increasing observability into customer-cited resources to maximize the 

7 value of these emerging grid-edge functions and services [54].

8

9 3.3.2 Emerging customer-driven control schemes

10

11 Value creation in the grid was once as predictable and unidirectional as the powerflows. But 

12 an interoperable smart grid allows value to be created in and flow between domains in new 

13 and potentially unexpected ways. The traditional system operations architecture had very 

14 little impact on customers other than through the economic and reliability metrics for the 

15 provided electric service. 

16

17 As consumers move to being active participants in the operation of the grid, the architecture 

18 of the operational systems can influence how and why consumers choose to change from 

19 being simply a service delivery point. As illustrated in Figure 2, DERs and other capabilities 

20 available at the customer site and the periphery of the grid can dramatically impact utility, 

21 regional, and even societal goals. 

22

23 One example of this is in Hawaii, where distributed resources — including large quantities of 

24 customer-sited generation — are growing very rapidly. On four islands serving more than 

25 one-third of the state’s electricity customers, distributed resources will soon have larger 

26 aggregate generating capacity than conventional centralized generation resources [79]. The 

27 value propositions of distributed generation in Hawaii span numerous scales and 

beneficiaries, including reducing systemwide electricity costs,45 28 achieving state policy goals 

29 including renewable portfolio standards, and reducing pollution and other emissions from 

30 conventional generation in environmentally sensitive locations [80].

31

32 While value can flow extensively from the customer domain outward, it also flows 

33 extensively from an interoperable smart grid to the customer. As demonstrated in the Hawaii 

34 example and illustrated in Figure 3, emerging schemes focused on maximizing customer 

35 engagement and asset utilization can yield benefits from the financial, through reliability, to 

36 the environmental. Yet the control schemes to maximize these value propositions are 

37 emerging in real-time, and indeed the economic structures and operational capabilities 

38 necessary to properly and fully stimulate these functions and value streams may not be 

39 available today.

40

41 Interoperability requirements are a necessary precursor to modern grid operations strategies 

42 seeking to maximizing the efficacy of growing equipment and technology investments across 

43 the system. These requirements will have to be refined as new technologies emerge and grid 

44 functionality expands.

45 Most Hawaiian electricity is generated using oil for fuel, which carries with it a high cost of generation. 
38

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1 Incorporating customer resources in utility control schemes

2 A Minnesota electric cooperative case study

3

4 Utility and customer focused 

5 control schemes are not mutually 

6 exclusive and are regularly 

7 combined in utility operations. 

8 Just as the High DER and 

9 Microgrid Communication 

10 Pathways Scenarios in this 

11 Framework highlight direct 

12 communications with customer 

13 sited assets (former) or 

14 management systems (latter), 

15 utilities regularly incorporate 

16 customer-owned assets as 

17 operational resources through demand management programs.

18

19 Electric cooperatives in Minnesota utilize a number of customer-focused control schemes to 

20 complement conventional electricity supply and grid management technologies. For 

21 example, Great River Energy’s 28 distribution cooperatives serve 700,000 customers [81], 

22 200,000 of which participate in demand response programs [82] totaling 400 MW capacity 

23 equal to 12 % of the cooperative’s generation resource [83]. The customer-sited load 

24 management program leverages technologies ranging from interruptible water heaters to 

25 irrigation pumps to microgrids. The distribution cooperatives employ a variety of control 

26 schemes to initiate the load curtailment, from direct load control techniques used to cycle 

27 customer-owned water heaters and air conditioners as illustrated in the High DER 

28 Communication Pathways Scenario 

29 (see Figure 11), to calling on 

30 campus microgrids to self-supply 

31 and reduce system load in an 

32 approach which mirrors the 

33 customer-owned microgrid 

34 illustration in the Microgrid 

35 Communication Pathways Scenario 

36 (see Figure 12).

37

38 Incorporating customer-sited 

39 resources and control schemes into 

40 their conventional electricity 

41 supply model has saved Minnesota 

42 electric cooperatives millions of 

43 dollars, with load management programs at Dakota Electric yielding economic efficiencies 

44 exceeding 8% of total revenue [84]. These benefits are achieved even as several of the 

45 resources are infrequently called upon [85]. Improvements in control theory and 

46 interoperability could further empower customers and yield significantly greater benefits.

Utility Service Providers

Business Systems 

Internet

System Operations

Customer

LAN / WAN

Distribution Ops

 Distribution 

Third-Party 

Service Providers

Transmission

Generation 

& Trans Ops Advanced Distribution Management 

System 

Business Systems 

Gateway

LAN/WAN AMI Telemetry

Network 

Aggregated 

Control 

Systems

Ops Services

System 

Modeling & 

Planning Tools 

3rd Party HeadEnd System

Weather 

Service Advanced 

Analytics

Load Profile

Calculation

Advanced Load 

Forecasting

Automated 

Generation 

Control

Generation 

Management 

System

Intelligent 

Electronic 

Devices

Distributed 

Controllers

VVO 

Sensors

Distribution 

Automation

Fault 

Circuit 

Indicators

Remote 

Switches

Home Area 

Gateway 

Markets

Energy 

Market 

Clearinghouse

Congestion 

Management

Energy 

Dispatch

Ancillary 

Services

Market 

Clearinghouse

Capacity 

Market 

Clearinghouse

Ancillary 

Services 

Dispatch

Energy 

Management 

System

HVAC 

Devices

Utility 

Meter

Generation including DER

DLC

&

DR

Devices

DER 

including 

Energy 

Storage

Meter Data 

Management 

System (MDMS)

Operational Enterprise Service Bus

Enterprise 

Resource 

Planning

Customer 

Info System

Billing 

System

Advanced 

Transformers

Smart 

Inverter

Electric 

Vehicle

Internet

DER Energy 

Storage

Participating 

Load

Participating 

Generation $

Gateway, Data 

Translator, IP SCADA 

Communications

Admin Enterprise Service Bus

DR Head 

End

Generator 

Control 

System

Bulk 

Generator

Bulk

Generator

Bulk

Generator

Substation 

Devices

CoGeneration

Smart

T-stat

DR 

Devices

Sub Meter

Customer Systems

Energy 

Audit Apps

Email Apps Account 

App

Billing App Usage Apps

Outage 

Apps

Service 

Order

App

Smart 

Appliances

Building 

Automation 

and Control 

System

Source: DRAFT NIST Smart Grid Framework 4.0

Cap Banks/ 

Controllers

Substation 

Controller

Enterprise 

Asset 

Management 

Geographic 

Information 

System 

Workforce 

Management 

System 

State Estimation 

& 

Grid Optimization

Outage 

Management

Economic and 

Reliability 

Management

Distributed 

Energy Resources 

Management Sys.

Figure 11 – The NIST High DER Communication Pathways Scenario, 

highlighting a representation of utility direct load control programs

Figure 12 – The NIST Microgrid Communication Pathways Scenario, 

highlighting a representation of utility voluntary load curtailment 

programs for industrial and commercial customers
39

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1 3.3.3 System devolution

2

3 Observation and control capabilities are extending to the edge of all grid systems. Enabled 

4 by declining technology costs [17] and occurring in every smart grid domain — as 

5 exemplified in the Hybrid Communication Pathways Scenario (see Section 2.2.4) — the 

6 need to manage expanding capabilities and faster response times means grid control has 

7 begun migration toward system peripheries.

8

9 The introduction of automated protection schemes for substations and other equipment 

10 necessitated the dispersal of certain actuator controls. Where system operations once relied 

11 almost exclusively on phone calls and other interpersonal dispatches from centralized 

12 operations centers, modern protection decisions and corresponding actuations must occur in 

13 the sub-cycle timeframe (<15ms). These actions are now made automatically in response to 

14 local conditions by equipment that uses logic and governance structures sanctioned by a 

15 central authority or operations center.

16

More than just a function of protection schemes, control devolution46 17 is progressing 

18 regardless of system architecture as optimization strategies evolve to incorporate and rely 

19 upon the local actions of DERs and other technologies. Campuses as microgrids, automated 

20 building management systems, and emerging distribution level market platforms all rely on 

21 devolution of grid control systems that empower local actors to provide value to system 

22 operations. More work is required to understand the evolving interoperability requirements 

23 associated with the devolution process. 

24

25

26 3.4 Emerging Interoperability Requirements

27

28 Physical interactions with the grid now entail a dynamism governed by both the physical 

29 conversion of electrical energy into work, and the application for which that energy has been 

30 harnessed. The resultant feature-space from these physical interactions may — depending on 

31 the operational objectives — require development of new observational techniques or control 

32 strategies, which in turn could drive associated informational interoperability requirements.

33

34 Where interoperability has historically been considered an informational challenge [19], the 

35 unique physical interaction each device has with the electric grid (see Section 3.2.2) elevates 

36 the importance of physical interoperability alongside the conventional information-based 

37 aspects of interoperability. Emerging interactions between end-use devices and the grid —

38 intended or otherwise — mean our understanding of physical interoperability must evolve to 

include functional aspects and be much more than the design of the physical connections.47 39

46 Traditionally defined as the transfer of power or authority from centralized government to local institutions, the term 

devolution is employed here to describe the emerging independence of localized control actions that affect device and 

system interactions with the power system.

47 For example, socket and plug design.
40

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1 3.4.1 Requirements for metrology, observability, and controllability

2

State awareness48 3 is at the heart of grid operations. Whether through central operations or 

4 distributed local control, knowing the operating status and conditions of the grid and 

5 connected assets provides context for control actions and economic signals alike. This is true 

6 even for automated devices, where at a bare minimum knowledge of whether the grid is up or 

7 down and whether grid following or grid forming functions are needed is required for safe 

8 operations.

9

10 Measurement is a prerequisite for state awareness, and a fundamental requirement for 

11 optimizing any cyber physical system—the electric grid included. The measurement 

12 parameters must be properly designed to capture the physical phenomena of interest, which 

13 becomes more challenging as the physical interactions of devices with the grid become more 

14 dynamic and complex (see Section 3.2.2).

48 Also called the “States” functional concern in CPS ontology, see Appendix B – Mapping CPS Aspects and Concerns to 

the Electrical Grid.
41

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1

2

3 Figure 13 – Smart meter accuracy under high harmonic waveform loads

4 Perceptions that smart meters are grossly inaccurate have impeded progress towards 

5 achieving the benefits that could be realized with deployment. One 2016 study [86] stated 

6 that more than half of the smart meters evaluated had measurement errors near 500 percent, 

7 indicating the likelihood of overbilling. News media reports around the world cited the 

8 study[87-89], as have groups and individuals who oppose smart meter deployments [90, 91].

9

10 Many have drawn erroneous conclusions about smart meter accuracy because of this study, 

11 especially because the smart meters tested were not built to the latest standards. For 

12 example, U.S. smart meters must comply with the American National Standard for 

13 Electricity meters, ANSI C12.20-2015 [92], published in 2017. It “is the most ambitious and 

14 significant update to the standard since its inception in 2998,” stated NIST’s Shannon 

15 Edwards, Char of ANSI C12 Subcommittee 16. It “addresses the challenges of metering in 

the 21st 16 -century environment head-on,” as the standard includes harmonic waveform testing 

17 to ensure metering accuracy with distorted loads.

18

19 NIST subsequently developed a testbed to examine the effects of harmonic distortions on 

20 smart meter measurements, similar to those in the 2016 study [72]. NIST’s tests used eight 

21 U.S. smart meters manufactured since 2015 and in compliance with the ANSI standard. 

22 NIST’s tests showed meters designed to accommodate the harmonics described in the 

updated ANSI standard have very good accuracy,49 23 thus proving that measurement accuracy 

24 can be achieved even for the most complex emerging system dynamics.

49 Three meters showed variations only within the test uncertainty, or almost 0 percent error. Of the meters exhibiting 

measurable error, single meters exhibited maximum errors of -1 percent, -2 percent, and +2 percent, while two meters 

exhibited maximum errors of +4 percent. No meter tested exhibited errors within two orders of magnitude of those found in 

the 2016 study.
42

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1 Fortunately, the challenges posed by the emerging system and waveform complexity do not 

2 preclude proper measurement. The NIST research that produced the highly distorted 

3 waveforms in Figure 10 and described in the text box above also demonstrated that smart 

4 meters designed to meet the ANSI C12.20-2015 accuracy requirements [92] were broadly 

5 able to do so (see Figure 14, [72]). It is clear that measurement accuracy is possible under 

6 even the harshest of conditions, but achieving the required accuracy requires an 

7 understanding of emerging system and waveform characteristics.

8

9

10 11 Figure 14 – Example smart meter measurement accuracies for highly distorted waveforms

12

13 But measurement alone does not yield observability, which is a prerequisite for state 

14 awareness. Observability is achieved through the coordinated and timely evaluation of 

15 diverse measurements across the system, a fundamentally different endeavor from making 

16 individual measurements. As described in Section 2.3.2 and Appendix B – Mapping CPS 

17 Aspects and Concerns to the Electrical Grid, a number of system functional concerns must be 

18 addressed to achieve state awareness, including: sensing, measurability, communication, 

19 monitorability, and uncertainty, among others. 

20

21 Well-designed requirements can yield measurability, observability, or other system 

22 capabilities. But the requirements associated with each concern are not constant across 

23 function, and evolve with physical and application context. For example, phasor 

24 measurement units (PMUs) typically measure line voltage 10,000 times or more per second, 

25 yet only report the phase data 30 to 60 times per second. This is because of the different 

26 sample rate requirements necessary for directly measuring electrical dynamics and that for 

27 observing much slower acting system dynamics and state changes.

28

29 Similar to the difference between temporal requirements for measurement and observability, 

30 the requirements for system control tend again to be orders of magnitude less stringent. This 

31 is especially so for centrally dispatched control signals, which tend to focus on timescales 

32 from minutes to hours.
43

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1

2 Time requirements for measurement, observability, and control:

3 A case study of oscillation damping in the Western Interconnect

4

5 As grid operations complexity has increased, questions have emerged over timing 

6 requirements for the system. Monitoring and control schemes derived for emerging grid 

7 applications and large geospatial areas have developed particularly stringent requirements for 

8 time awareness. The availability of satellite and network-based timing signals has led some 

9 to conclude that these accuracy requirements re easily achieved despite the technical 

10 challenges with doing so, and the introduction of communications standards premised on 

11 virtually unlimited bandwidth and minimal latencies (e.g., IEC 61850) compound this 

12 perception. But the difference in timing requirements for measurement, observability, and 

13 control applications are often misunderstood.

14

15 In 2017 NIST published a 

16 workshop report on Timing 

17 Challenges in the Smart Grid 

18 [93], in which expert consensus 

19 was developed around required 

20 time accuracy and precision for 

21 different applications and 

22 communication events in modern 

23 power systems (see Figure 15). 

24 Of note is that stated timing 

25 requirements for everything from 

26 measurement applications to 

27 communications events were all 

28 more stringent than a millisecond, 

29 with some requirements more 

30 than a thousand-fold more precise.

31

32 Around the same time, researchers were conducting the first full-scale experiments on 

33 damping wide-area oscillations in the Western Interconnect of the U.S. grid. Using 

34 distributed PMU measurement data – which have timing accuracy requirements of 1 

microsecond (106 35 Hz) for data acquisition – the scientists developed oscillation damping 

36 schemes [94] utilizing control signals which update at only 60Hz [95]. Further study on 

37 communications requirements for the same application indicated system damping could be 

38 achieved with latencies of up to 0.5 seconds [96].

39

40 This example – where timing accuracy and latency requirements span five orders of 

41 magnitude across measurement, observability, and control – demonstrates the importance of 

42 properly deriving requirements from both application and function. Additional research is 

43 required to fully characterize application- and function-specific timing requirements for 

44 power systems.

Figure 15 – Wide area precision time requirements in power systems
44

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1 3.4.2 Trustworthiness

2

3 Trustworthiness in the grid is often viewed from a cybersecurity perspective. It is generally 

4 understood to be whether devices or systems can be expected to preserve the confidentiality, 

5 integrity, and availability of the information being processed, stored, or transmitted by the 

6 system across the full range of threats [97]. This information-driven understanding of 

7 trustworthiness is inadequate for the electric grid, where nested hierarchical architectures and 

8 control systems create an operational paradigm wherein it is impossible for each higher-layer 

9 grid system to validate the activity of each subordinate edge device that impacts its 

10 operations.

11

12 This is particularly important for the electric grid as edge devices, or field level nodes, 

13 continue to gain energy production and management capabilities. Field nodes can actively 

14 communicate with sibling nodes, and therefore develop coordinated actions that amplify the 

15 impact of control actions by individual field nodes on the superior system. This highlights 

16 the importance of developing a rigorous approach to operational trustworthiness.

17

18 This is why the aspects of a modern electrical grid described in Section 2.3.2 highlight that 

19 trustworthiness for a cyber physical system includes physical security, reliability, and 

20 resilience in addition to the typical informational trustworthiness concerns. For the electric 

21 grid, the reliability and resilience concerns are critical to developing the interoperability 

22 requirements for lower level systems and edge devices. From Appendix B – Mapping CPS 

23 Aspects and Concerns to the Electrical Grid:

24

25 Trustworthiness → Reliability: Concerns related to the ability of the grid, or 

26 components within a grid, to deliver stable and predictable performance in expected 

27 conditions.

28

29 Trustworthiness → Resilience: Concerns related to the grid, or components within 

30 a grid, to withstand instability, unexpected conditions, and gracefully return to 

31 predictable, but possibly degraded, performance.

32

33 Were the CPS definition of trustworthiness achieved in the grid, the interoperability 

34 requirements for subordinate systems or nodes could be limited to initial operational status—

35 likely determination upon connection—and subsequent status updates only when the 

36 operational state changes. If complete trustworthiness is achieved, field nodes might never 

37 require exposure to the system operator. This trusted ideal is in marked contrast to the input 

38 NIST received during a recent set of workshops, wherein some participants emphasized that 

39 utilities may need to continuously monitor all DERs on a system — including those 

40 contained within customer-owned microgrids — to ensure the utility can manage 

41 contingency operations [54].

42

43 The reality of operational trustworthiness will likely fall somewhere in between the full-trust 

44 and zero-trust options described above. Trustworthiness of a device or system node, and the 

45 related effects interactions among many nodes will have on operational trustworthiness for 
45

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1 the system, must be better characterized before interoperability requirements can be properly 

2 established.

3

4 Testing and certification are mechanisms to improve trustworthiness across the system. For a 

5 detailed discussion on these issues, please see Section 6 – Testing and Certification. 

6

7 3.5 Interoperability for Customer Empowerment

8

9 The future grid will benefit from — and require — innovation spanning all domains. As 

10 noted in Section 3.3.1, resource flexibility, power electronics, distributed intelligence, and 

11 adaptive protection are all necessary for future utility control schemes. These and other 

12 technical innovations will also profoundly impact the customer, as new capabilities will 

13 enable the motivated customer to realize substantial benefits from new interactions with the 

14 grid.

15

16 But the many benefits illustrated in Figure 3 cannot all be achieved through technology 

17 alone. Indeed, most of the benefits can accrue only after the customer becomes engaged with 

18 physical, information, or market systems outside the home, and these benefits accrue more 

19 rapidly as interoperability increases. Three primary ways customers and grid operations 

20 benefit from interoperability include [52]:

21

22 Breaking asset specificity: Consumer devices are often packed with extra 

23 capabilities in an effort to improve convenience or enjoyment. Interoperability allows 

24 harnessing of these extra capabilities to improve energy operations. For example, a 

25 thermostat’s sole function is to control the temperature in a building. Remote access 

26 was added for customer convenience, and interoperability across organization and 

27 platform now allows thermostats to be enrolled in numerous energy management 

28 schemes allowing customers and utilities to co-optimize their comfort, infrastructure, 

29 and operational priorities.

30

31 Market access: Barriers to market entry have historically been large in the 

32 electricity space, where wholesale market entry required asset scales not typically 

33 achieved at the customer level. Interoperability decreases integration costs and 

34 enables asset aggregation, which expands market access for customers and the pool of 

35 market resources for utilities to utilize. Aggregation may also improve the bargaining 

36 position of customer-sited assets vis-à-vis other stakeholder groups, thereby 

37 improving profitability.

38

39 Reduce transaction costs: Full interoperability largely eliminates the cost of 

40 executing a transaction. The result is that small-scale transactions executed by or 

41 among customers can be utilized to optimize their engagement with the system.

42

43 Importantly, combining interoperability benefits creates a virtuous cycle wherein opportunity 

44 grows with additional capability. For example, using interoperability to break the asset 

45 specificity of a thermostat allows customers to enroll in utility managed direct load control or 

46 demand response programs. Using interoperability to facilitate market access through 
46

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1 aggregation allows customer-sited thermostatically controlled demand response resources to 

2 bid into wholesale electricity markets in addition to engaging utility direct load control 

3 programs. 

4

5 By stacking interoperability benefits as described above the customer is able to pursue the 

6 best value opportunity. Doing so not only ensures optimal return on the customer’s 

7 investment, but also ensures customer resources contribute to addressing the most important 

system needs.50 8

9

10 Reducing transaction costs allows for smaller and more frequent transactions, which will 

11 allow development of new market structures to enable optimization at the system edge where 

12 utility control schemes typically have little—if any—visibility or control. The benefits of 

13 this are not yet fully understood, but could be significant given that substantial efficiency and 

14 economic benefits have been realized in electricity systems even when market transactions 

15 are used to optimize only a small percentage of system generation [98].

16

17

18 3.6 Future Work

19

20 In general, the role, benefits, and beneficiaries of interoperability require further study and 

21 elucidation. Characterization of the ancillary benefits from interoperability investments that 

22 cross system and domain boundaries is a particular need. 

23

24 Interoperability requirements and metrics should derive explicitly from the physical 

25 requirements and constraints of specific applications and interfaces. In some instances, this 

26 may require transitioning away from interface abstraction and towards establishing specific 

27 interoperability profiles that describe a constrained set of implementation options. For a 

28 deeper exploration of this issue, please see Section 6.

29

30 The relationship between interoperability and the changing physics introduced by 

31 semiconductor technologies and new system configurations requires deeper understanding. 

32 Interoperability requirements could derive from the need to measure and/or observe 

33 phenomena that are not currently considered during conventional grid operations, and also 

34 the need for automated or dispatched control to manage the system effects. 

35

36 Emerging interfaces between DC and AC systems in the smart grid should be factored into 

37 research to expand our understanding of system optimization and control theory. The 

38 industry would benefit from developing some standards around DC systems and microgrids 

39 and their interfaces with the broader AC grid, while taking care to avoid unnecessary or over40 specification.

41

42 As active control pushes towards the system edge and sibling field nodes communicate and 

43 coordinate activity, emergent behavior issues need study. Clarifying the relationship of 

44 interoperability to control strategies that can manage these potential behaviors would be 

45 beneficial. 

50 This assumes economic incentives are properly aligned with system need.
47

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1

2 4 Economics

3

4 The electric grid exists to serve the energy needs of a dynamic economy. The growth of the 

5 sector over the last century and the success of its stakeholders in realizing improvements 

6 while operating continuously are evidence of the system’s efficacy. Electrons are incredibly 

7 high-quality energy carriers that can be used for any application. The breadth of this 

8 applicability contributes to the sector’s capacity for value creation and broad attractiveness. 

9 As households and firms have responded strategically to energy related incentives and the 

10 economy has oriented itself around the electric grid, this infrastructure is increasingly critical 

11 to the continuity and growth of modern civilization.

12

13 The inseparable linkage between electric infrastructure and economic growth does not mean 

14 the relationship must remain unaltered. Technology, policy, and stakeholder expectations 

15 each affect the strategies by which the system is optimized, and the economics of value 

16 creation. Increasing interoperability will enable changes toward more cooperative and 

17 collaborative operating strategies for the electric power sector at a time when society expects 

18 and needs it to contend with all hazards while delivering on myriad new value propositions. 

19

20 The challenges confronting the electric grid are manifold. With new problems comes the 

21 inevitable call for new problem-solving capacity. This combination of challenges and 

Key Messages – Economics

Interoperability is key to the economics of the future grid. The traditional means of 

ratemaking and cost recovery are under strain as growth in distributed energy resources and 

changing customer capabilities alter traditional economic dependencies.

Reducing information asymmetry through interoperability helps ensure the technical and 

economic benefits from grid modernization flow across smart grid participants and accrue to 

all stakeholder classes. Interoperability is therefore a critical enabler of customer 

empowerment and value creation.

Interoperability can minimize transaction costs and entry barriers to market participation, 

thereby facilitating the creation of new participatory and economic opportunities across the 

system and enabling customer choice as they seek to integrate their equipment into the 

system’s value network.

Interoperability reduces limitations caused by asset specificity, and in this way facilitates 

combinatorial innovation and value stacking which can improve stakeholder value 

propositions across the sector.
48

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1 solutions adds complexity to the power system discussed throughout this Framework. 

2 Acknowledging that “every increase in complexity has a cost” [99], this chapter presents a 

3 discussion of the central role for interoperability in ameliorating such costs and adding new 

4 value to the system. Through improving interoperability, the core mission of serving the 

5 energy needs of a diverse and dynamic set of customers will be ever-more achievable.

6

7

8 4.1 Economics of the Conventional Utility

9

10 4.1.1 Functions of electric utilities

11

12 The electric industry in the United States is both highly diverse and highly fragmented. It 

13 consists of a mix of entities, ranging from heavily-regulated utilities whose profitability and 

14 system investments are determined through public hearings and dockets with utility 

15 commissions, to those which operate competitively in deregulated markets. Utilities include 

16 investor-owned utilities, quasi-governmental entities, municipalities, and cooperatives. In 

17 total there are more than 3,000 utilities spread across the 50 states. Some are regulated by 

18 state or federal regulatory commissions. Others are overseen by government entities, or in 

19 the case of cooperatives managed as not-for-profit entities for their members by their 

20 governing boards. 

21

22 In addition to utilities, there are numerous companies that participate in the competitive 

23 generation sector, either as their core business or, in the case of co-generators, as a byproduct 

24 of their core business activities. The emergence of DERs which may be owned by utilities, 

25 competitive or collective entities, or individuals—and also the incorporation of demand 

26 response resources into conventional energy markets—complicates the supply-side 

27 economics. Finally, there are competitive electric service providers that serve as 

28 intermediaries between customers and markets, providing energy services to customers or as 

29 aggregators of loads and/or services to markets.

30

31 The function of any given utility typically includes three services: generation, transmission, 

32 and distribution. In states that have restructured, the investor-owned utility has sold off its 

33 generation assets to a third-party owner, and the transmission system is operated by a 

34 Regional Transmission Operator (RTO) or Independent System Operator (ISO). 

35 Additionally, those states may also allow customers to choose a competitive supplier to 

36 provide their electricity needs, which leaves the monopoly as the “poles and wires” company 

37 responsible for distributing the electricity to end use customers.

38

39 In other states, vertically integrated utilities, which own generation, transmission, and 

40 distribution assets, operate as regulated monopoly providers of electricity to end-use 

41 customers. Some vertically integrated utilities are in organized wholesale markets, operated 

42 by an ISO or RTO, and others operate in less structured markets.

43

44 While this portrayal of the industry as complex and fragmented is accurate, there is also a 

45 high level of consistency in the value provided by each group based upon the overall role that 

46 they play within the industry. The Smart Grid Conceptual Model is useful in defining this 
49

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1 core set of industry roles, and is described further in Appendix D – The Core Set of Electric 

2 Industry Roles.

3

4 4.1.2 Cost structures

5

6 Utility costs are typically differentiated between capital and operating and maintenance 

7 (O&M) costs. In general, capital costs earn a higher return on equity (ROE) than O&M costs 

8 [100]. The ROE is set by the regulator during the rate case or during a separate cost of 

9 capital proceeding. Examples of capital costs include construction of new infrastructure, like 

10 a power plant, transmission line, or substation. Examples of O&M costs include 

11 maintenance costs for power lines, operational efficiencies, or utilization of software as a 

12 service or cloud-based services.

13

14 Due to this structure, utilities earn more profit via capital projects than O&M projects, which 

15 impacts utility investment strategies. This becomes important when considering 

16 interoperability, as it may be competing against a capital project which earns a higher ROE.

17

18 Costs are also treated as either long-term and variable, or short-term and fixed. Costs that are 

19 treated as variable are recovered through the variable component of the rate and recovered 

20 through volumetric charges. Treating certain costs as fixed allows the utility to have greater 

21 certainty in recovery of those costs, as the regulator considers costs associated with those 

22 investments as necessary for service provision. This has a significant impact on the rate 

23 design and bills as a high fixed charge, while providing the utility greater certainty on the 

24 recovery of its authorized revenue requirement. This means fewer costs are recovered in the 

25 variable rate. When variable rate cost recovery diminishes per this relationship, the price 

26 signal to customers is muted and limits the ability of the customer to invest in technologies to 

27 lower their bills.

28

29 4.1.3 Ratemaking

30

31 Review of utility costs is traditionally based on least cost ratemaking. This means that the 

32 utility is to spend the least amount of money needed to provide safe and reliable electricity 

33 service, plus a rate of return (i.e., profit). As the utility industry grew, the ability of the utility 

34 to scale large assets was a preferred means of meeting utility service obligations, and so large 

35 capital investments were regularly considered least-cost. 

36

37 Additionally, the early models of utility economics focused on the societal goods of 

38 expanding access and increasing electricity use. This meant that, by expanding the rate base, 

39 utilities could recover their costs across more kilowatt hours and provide sufficient electricity 

40 to an expanding set of customers.

41

42 Because utilities generate revenue through electricity sales, they are incentivized to sell more 

43 electrons. During the 1970’s, however, some states began experimenting with a different 

44 way of setting rates via a mechanism called decoupling. Decoupling is a means by which a 

45 utility’s revenue requirement and profit is not driven by sales, but by the authorized revenue 

46 requirement set by the regulator. In other words, the utility is guaranteed to recover its 
50

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1 authorized revenue requirement regardless of how much (or how little) electricity the utility 

2 sells. Decoupling allows utilities to maintain profitability even while encouraging lower 

3 consumption, for example through improving customer efficiency. However, decoupling 

4 does not address the profit incentive towards increasing capital expenditures.

5

6 This discussion of utility cost structures and ratemaking is intended to provide high-level 

7 economic context for the examination of interoperability costs, benefits, and value that 

8 follows. Additional information on ratemaking, cost recovery, and rate design is found in 

9 Appendix E – Cost Recovery, Rate Design, and Regulation.

10

11

12 4.2 Evolution of the Distribution Utility

13

14 The electricity network exists to provide customers with access to electricity to power their 

15 lives and industry. As described in the Operations section of the Framework (Section 3), the 

16 integration of modern technologies and resources means the electricity system is embarking 

17 on a substantial evolution towards a two-way delivery system with the capability of relying 

18 on local resources to meet system needs. This will result in the distribution utility taking on 

19 additional roles that it has not fulfilled in the past, including more detailed modeling of the 

20 distribution system, customer demand, and optimization and utilization of resources located 

21 either at the customer site or close thereto.

22

23 4.2.1 Changes to utility organizational structure

24

25 Distribution utility operations are changing with increasing DER adoption. Whereas in the 

26 past the distribution system delivered electricity to end use customers, the distribution grid 

27 must now be organized and operated to handle two-way electricity flows. The emerging 

28 power flow complexity hints at an underlying transition in domain function and actor role. 

29 Where distribution utilities were built to service customers who were purely consumers of 

30 electricity, utilities may now be the recipients of services provided by customers, or even the 

31 facilitator of the exchange of services between customers. 

32

33 Just as two-way electricity flows complicate system operations, system economics become 

34 similarly more challenging. Where utility cost recovery has historically been manageable 

35 through simple tariff structures consisting of energy and demand charges (see Appendix E –

36 Cost Recovery, Rate Design, and Regulation), the economics of cost recovery will have to 

37 change as technology allows customers to self-supply energy or locally develop and 

38 exchange services. 

39

40 Evidence has also emerged in recent years of an ongoing disruption of the historic linkage 

41 between energy consumption and economic growth. Although absolute electricity 

consumption continues to rise across the country (see Figure 16),51 42 the decoupling of 

43 economic and societal outputs from energy consumption has yielded a flattening (and even a 

44 decline) of per-capita electricity consumption across the country [101]. The effect on 

51 Analysis of Energy Information Administration form 861M data indicates that absolute electricity consumption has risen 

in 49 of 50 U.S. states
51

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1 account-level consumption has been stark, with average customer consumption in 39 states 

2 and the District of Columbia — representing nearly 80 percent of electricity demand in the 

United States — declining since 2010 (see Figure 16).52 3 This dynamic of declining per4 customer consumption has eroded the reliability of the sector’s historical cost-recovery 

5 approach and raised concerns over optimal utility function [102] and tariff structures [103]

6 for the future. 

7

8 There are many ways to describe the future organizational and operational structures of the 

9 electric utility, but a commonly used term is that of the distribution system operator (DSO) 

10 [36]. Although some might correlate the DSO terminology to the introduction of 

11 independent market operators to the distribution system, this need not be the case. In this 

12 report — as elsewhere [104] — the term DSO is used to describe a system where utility 

13 functions will necessarily expand beyond those conventionally provided by the historic 

14 utility. 

15

16 No single business model or market function is implied through our use of the DSO term. 

17 Yet as has been described throughout this Framework, the DSO must provide some 

18 additional capabilities which allow the system to utilize and optimize resources other than 

19 those owned by monopoly utilities in servicing customers and other market participants. 

20 This, in turn, impacts the utility business model.

21

22 4.2.2 Performance-based regulation

23

24 As the utility business model evolves, so too must the mechanisms by which utilities recover 

25 costs. One approach is to move to a performance-based ratemaking scheme. This type of 

26 regime provides utilities with additional revenue for achieving certain performance metrics, 

27 such as enhanced reliability, faster integration of DERs, or customer satisfaction rates. This 

28 type of cost-recovery is intended to offset the capital bias inherent in cost-of-service 

29 ratemaking (see Appendix E – Cost Recovery, Rate Design, and Regulation).

52 Per customer electricity consumption in 2018 was lower than in 2010 for AK, AL, AR, AZ, CA, CO, CT, DC, DE, FL, 

GA, HI, ID, IL, IN, KS, KY, MA, MD, MI, MN, MO, MS, MT, NC, NE, NH, NJ, NY, OH, PA, RI, SC, TN, UT, VA, VT, 

WA, WI, and WY, representing 78.5% of national electricity demand.

Figure 16 – State-level absolute and per-customer electricity consumption trends
52

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1 4.2.3 Economics of changing operations

2

3 While the physical aspects of changing utility operations are discussed extensively in Section 

4 3, the relationship between the economics and physical operation of a system with expanding 

5 capabilities warrants examination. With expanding distribution utility functionality,

6 modernizing business models, and DER proliferation, the mechanisms used to ensure optimal 

7 deployment of grid resources can be expected to change.

8

9 For example, in California the distribution resource planning process includes analyses, by 

10 line segment, of the hosting capacity as well as the value of DER on the grid at that location. 

11 Distributed resources, including demand response and non-wires alternatives, can therefore 

12 be sited in specific locations where it can be expected to provide greater optimization of the 

13 grid as a whole. More broadly, through incorporation of economic signals linked to spatial, 

14 temporal, and topological optimization constraints, incentives will exist to locate and utilize 

15 DER where it provides the greatest value to the grid — including to customers.

16

17 Developing economic mechanisms to optimize DER deployment and utilization will likely 

18 increase overall asset utilization, and create a virtuous cycle where legacy infrastructure can 

19 be maintained for a longer service life. For example, deployment of demand response and/or 

20 energy storage resources may prove to be a more economical solution to alleviate an 

21 overcapacity constraint on a feeder or substation — as opposed to a more traditional 

22 approach of rebuilding infrastructure to increase capacity. These non-wires alternatives are 

23 regularly employed as alternatives to distribution system construction investments [105]. 

24 Placing resources closer to the load they serve can additionally be expected to reduce overall 

25 cost and physical energy losses of delivering energy to customers.

26

27 Identifying locational net values for DER, including possible development of locational 

28 marginal pricing and distribution-level energy markets for energy and other grid supporting 

29 services, can be expected to effectively flatten the load, increase the utilization of existing 

30 assets, and broaden the participation in energy market or optimization services. Participation 

31 would expand directly through individual DER ownership, and indirectly with the 

32 participation of aggregators and energy service providers. The same distribution-level 

33 incentive can help ensure all market participants are equitably compensated for the energy 

34 and services they provide. This is an especially important consideration as customers are 

presented with an ever-increasing range of energy investments53 35 that offer the potential for 

36 economic value previously unavailable to them and independent of the local utility.

37

38 A discussion of some specific utility organizational and operational structures is found in 

39 Appendix F – Distribution Platforms and Markets.

53 For example, community solar or storage projects, energy management systems, demand response programs, or customer 

owned and sited DER technologies ranging from solar panels to electric vehicles and home energy management tools.
53

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1 4.3 Factors Affecting — and Benefits From — Interoperability

2

3 The electric power sector stands on the precipice of a period of great “combinatorial 

innovation” just as expectations of and within the industry are changing rapidly.54 4 Increasing 

5 technical and organizational modularity within the sector have opened opportunities for 

6 innovation by incumbents and new entrants. Recent developments are consistent with past 

7 historical experiences in which a “set of technologies comes along that offers a rich set of 

8 components that can be combined and recombined to create new products” [107]. Modular 

9 and distributed energy resources, coupled with entrepreneurial capabilities and encouraged 

10 by an awakening customer base, promise to remake the structure of electricity markets and 

11 value creation.

12

13 The current influx of information and communications technology (ICT) to the electric grid 

14 has brought with it organizational perspectives and processes for the accelerated 

15 development and deployment of new technologies. Other sectors extensively impacted by 

16 ICT exhibit rapid rates of technological adoption, one of the major drivers of which has been 

17 a relaxing of the requirement for detailed modeling and analysis prior to technology adoption 

18 [108]. While electric utilities cannot forgo the economic analysis to justify equipment 

19 expenditures or the detailed examination of operational models prior to technology adoption, 

20 customers accustomed to the ICT-enabled conveniences of digital service offerings available 

21 in other sectors have formed new expectations about the electric services they consume.

22

23 Electric utilities face significant uncertainty with respect to their future operating 

24 environment (see Section 3). Managers (and regulators) are therefore concerned with the 

25 pursuit of no-regrets moves that will pay off regardless of how the uncertainty is ultimately 

26 resolved. Cost-cutting initiatives are prototypical examples of such regret-free strategies 

27 [109]. One important source of uncertainty in the electric power sector has to do with the 

28 cost of integrating new technology with the legacy grid and ensuring interoperability.

29

30 Uncertainty over integration costs may provide an impetus for investment in smart grid 

31 research, development, and deployment activities as firms seek to uncover actual cost 

32 structures through exploratory efforts. However, a lack of consensus regarding which 

33 standards are most important for interoperability—or even how to select requirements to 

34 achieve interoperability through existing standards (see Section 6)—may constrain the set of 

35 no-regrets moves and constitute a barrier to investment in distributed energy resources and 

36 other emerging technologies. In the near term, as system integration is pursued in an ad hoc 

37 manner, a high-degree of solution specificity is to be expected.

54 Invention entails the integration of existing concepts, devices, and systems to deliver new capabilities. The rate of 

invention reflects the readiness of ease with which these parts can form new and useful amalgams. Combinatorial 

innovation occurs when a diverse collection of components becomes ripe for synthesis, and market actors rapidly succeed at 

creating and improving many and varied value propositions through the novel recombination of these parts [106]. Greater 

interoperability should catalyze combinatorial innovation within the electric power sector.
54

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1 4.3.1 Interoperability and specificity

2

3 The complexity of the electric power sector value chain is increasing with the proliferation of 

4 specific solution implementations for a range of new operational challenges, especially DER 

5 and customer-owned asset integration. Asset specificity often results from efforts to meet 

6 technical or regulatory requirements and meaningfully contribute to the value chain. 

7 Increasing specificity leads directly to rising transaction costs as the technology stack 

8 supporting transactions becomes more diverse and complicated to maintain. Specificity may 

9 then act as a barrier to more extensive utilization of devices and systems.

10

11 Interoperability offers a strategy set through which to reduce “specificity barriers” and 

12 engender an environment conducive to combinatorial innovation by all stakeholders. Highly 

13 specific solutions to electric grid challenges are present on both the demand and supply sides 

14 of electricity markets. Consequently, interoperability strategies can improve stakeholder 

15 value propositions across the sector.

16

17

18 4.3.2 Interoperability and customer empowerment

19

20 On the demand side of electricity economics, interoperability is crucial to customer 

21 empowerment. A variety of concerns affect customer opportunity in the legacy grid, among 

22 which interoperability can help address:

23

24 Information asymmetry: Enhancements to interoperability should reduce 

25 informational imperfections that can afflict electricity markets and manifest as pricing 

26 conditions that traditionally favor producers—who are likely to enjoy an 

27 informational advantage—over consumers [52]. Interoperability enhancements 

28 should reduce information asymmetry and better inform customers about their own 

29 electricity-use decisions and technological investments. This in turn should allow for 

30 improved economic return on these actions and likely improve technology adoption 

31 outcomes.

32

33 Value stacking: Customer assets that often sit idle due to lack of outside options for 

34 application could be matched with new opportunities as interoperability increases and 

35 barriers to providing grid services fall. Capacity utilization and thus the value 

proposition of economically efficient customer assets55 36 will generally increase with 

37 the level of interoperability that exists between those assets and the rest of the electric 

grid.56 38 

55 Unlike merchant generators or utility-owned grid equipment, customers generally purchase assets primarily for priorities 

or to provide functions other than grid services. With overnight capital allocations justified for other purposes and fuel costs 

generally negligible for distributed renewable and demand response resources, customer assets may have very low marginal 

costs and can often generate value at modest grid services pricing.

56 Some assets that are no longer efficient when opened to competition from newly interoperable grid resources will be 

dispatched with decreasing frequency. The nature of this compositional shift in grid value networks will be determined by 

the details and dynamics of interoperability investment.
55

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1 Customer choice: Interoperability improvements can reduce barriers to entry and 

2 transaction costs paid by customers as they seek to integrate their equipment into the 

3 sector’s value network. Absent an environment that allows universal access to the 

4 full range of opportunities, customers may be required to select devices and systems 

5 for feasibility of integration rather than the operational or economic value 

6 propositions they offer. 

7

8

9 4.3.3 Complexity and cost structures

10

11 The electric power sector is confronting a complexity problem. Operational fragmentation 

12 and increasing specificity of assets means the process of producing and delivering electricity 

13 to customers has more — and more varied — stakeholders than ever. Regulatory status 

14 varies across the value chain, and coordinating value-adding activities in a manner that is 

15 consistent with customer expectations and regulatory requirements is costly. In many cases, 

16 it simply costs too much to make the fragments of the grid interoperate effectively. This lack 

17 of interoperability is the primary barrier of consequence to realizing the potential for 

18 combinatorial innovation in the electric power sector.

19

20 Interoperability investments will reduce, though not eliminate, some barriers to sectoral 

entry. Though some incumbents may be slow to embrace interoperability,57 21 support for 

22 greater standardization in pursuit of lower interoperating (transaction) costs is expected as the 

23 benefits become manifest. 

24

25 As interoperability improves and entry barriers are reduced, more participants are likely to 

26 enter the sector, which may bring additional capital investment resources to the electric grid. 

27 This is especially important as investment requirements for the grid are expected to rise 

28 substantially in the coming decades [110]. Interoperability improvements may therefore 

relax two important binding constraints58 29 on the electric grid: the constraint on capital 

30 available for investment, and the feasible set of investment opportunities for smart grid 

31 assets.

32

33 As an attribute of the electric grid, interoperability is challenging to achieve because it places 

34 requirements on the systems and components of multiple organizations which have to 

35 coordinate strategies while remaining in compliance with antitrust law. Institutions and 

36 mechanisms that make such coordination less costly and more dynamic will prove valuable 

37 to electric grid stakeholders. However, organizations investing in smart grid technologies 

38 need mechanisms to provide assurance that their equipment is fit for purpose and will work 

39 as intended and expected. Interoperability testing and certification programs will need to fill 

40 the role of such mechanisms (see Section 6 – Testing and Certification). 

57 Numerous factors affect the maturation of interoperability strategies across the sector. To the extent that integration costs 

are considered capital expenditures, utilities face perverse incentives to avoid minimizing integration outlays that increase 

the rate base.

58 A third important constraint is the regulatory construct which, at times, prevents grid investment. While non-utility 

investments may reduce customer costs, the relationships between these and regulated investments requires clarification. 
56

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1 4.3.4 Trust and assurance

2

3 Realizing an interoperable grid to enable growth in valuable services requires surmounting 

4 numerous challenges. Stakeholders must be able to trust that the electric grid on which 

5 modern society is built will continue to be reliable; such trust can be built on assurance. One 

6 working definition of assurance is “our estimate of the likelihood that a system will fail in a 

7 particular way” [111], which falls within the CPS trustworthiness concerns of reliability and 

8 resilience described in Section 3.4.2 and Appendix B – Mapping CPS Aspects and Concerns 

9 to the Electrical Grid. 

10

11 Previous trustworthiness discussions in this Framework focused on the effects operational 

12 trustworthiness would have on informational—and thus interoperability—requirements. 

13 Here, trust and assurance are examined from the perspective of the risk that components or 

14 systems will not be able to interoperate. Assurances that reduce the expected costs of 

15 integration improve the value proposition of investment options, encouraging more rapid and 

16 extensive technological adoption.

17

18 The interoperability assurances needed to accelerate adoption of smart grid technologies vary 

19 with the specific technology considered and the stakeholders in whom trust must be 

20 cultivated. There will always be costs associated with obtaining this assurance, although 

21 systematic approaches to achieving desirable assurances will prove more cost effective than 

22 ad hoc alternatives. The gap between these approaches will likely widen over time as 

23 interoperability strategies mature and evaluative organizations learn by doing.

24

25 Some might worry that movement towards standards will diminish product and service 

26 differentiation or limit innovation. Yet vendors can in fact differentiate their products and 

27 earn increased markups over marginal costs on products for which they can supply the 

28 necessary interoperability assurances to address their customers integration challenges. 

29 Implementers might willingly trade ballooning integration cost structures for set testing and 

30 certification costs.

31

32 Integration costs place an upper bound on an organizations’ willingness to pay for the testing 

and certification programs designed to obviate implementation barriers.59 33 Electric sector 

34 organizations can choose to opt in to employing assurance mechanisms that demonstrably 

35 reduce integration costs relative to in-house approaches. As the cost of systems integration 

36 rises with complexity, the opportunity for assurance mechanisms to create value will 

37 improve. As only about one in five smart grid interoperability standards currently has an 

38 independent testing and certification program [60], entry into this space is needed (see 

39 Section 6 – Testing and Certification).

59 As described in Section 3.1.1, the costs to utilities and equipment manufacturers for integrating non-interoperable 

equipment ranges from $140 million to $1 billion per year per firm.
57

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1 4.3.5 Testing and certification

2

3 Stakeholders across the electric power sector can generally agree that greater assurances with 

4 respect to equipment and system performance are needed [23], yet it is unclear how to share 

5 the burden — and benefits — of overcoming interoperability challenges. Testing and 

6 certification programs can reduce barriers to interoperability. Identifying and mitigating the 

7 barriers to these efforts is a necessary step towards achieving this goal.

8

9 The fixed costs associated with developing a testing and certification program can be 

10 considerable. Markets for specific testing and certification services must be sufficiently large 

11 to induce entry by testing and certification organizations. However, the electric power 

12 sector’s high levels of specificity and complexity have yielded a large enough number of 

13 interoperability relevant standards that the certification market for each is relatively thin. 

14 Thus, developing testing and certification programs remains relatively unlikely. 

15

16 Two approaches to increasing the availability of testing and certification services include 

17 reducing complexity of implementation and diminishing the barriers to entry. The 

18 development of interoperability profiles can help accelerate development of the testing and 

19 certification programs through reducing implementation complexity (see Section 6.5.1). An 

20 interoperability profile can define a subset of a given standard or set of standards on which 

21 stakeholders have agreed to focus their efforts. The crucial tradeoff in this approach is one 

22 that reduces degrees of freedom in implementation for decreased integration cost. 

23

24 Another approach to increasing the availability of testing and certification programs is to 

develop affordable tools such as test harnesses60 25 that can be employed by stakeholders to 

26 troubleshoot common implementation problems. This can free testing and certification 

27 organizations to focus their efforts on the most vexing system integration problems facing the 

28 sector.

29

30

31 4.4 Economics and Challenges of Certification Institutions

32

Achieving high levels of interoperability can be very costly.61 33 That interoperability is 

34 difficult to quantify (see Section 1.2.1) does not mean it is unachievable, but rather calls for 

35 advances in the sector’s measurement capabilities. And while interoperability can be hard to 

36 measure directly, the concepts of increasing transaction and integration costs are far more 

37 tangible. A low level of interoperability is prevalent in the market for smart grid solutions in 

38 part because utilities and other implementing stakeholders have a limited ability to discern 

39 between high and low interoperability options before they undertake systems integration 

40 efforts. This means that vendors are incompletely compensated for engaging in costly efforts 

41 that could improve the interoperability of their products.

60 Open-source test harnesses were identified as important interoperability enablers during NIST workshops [23] 61 High levels of interoperability are required for the maintenance and ongoing integration of old and new systems across the 

grid, as well as for the delivery of new services. Interoperability in electrical systems typically derives from extensive 

systems integration work that entails trial and error, learning by doing, uncertainty, and unpredictability. The strategic and 

context specific nature of these efforts implies that lessons learned are generally incompletely communicated between 

stakeholders, increasing the likelihood for costly duplication of work. 
58

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1 A situation in which buyers, suppliers, and regulators lack all the information necessary to 

2 make an informed decision is known as imperfect information. Furthermore, as vendors and 

3 implementors likely possess different amounts of information regarding the ultimate quality 

4 and value of a system to be integrated, information asymmetry also afflicts the market for 

5 smart grid solutions. Both of these informational problems have a chilling effect on 

6 investment—especially in regulated commodity environments—that can hinder grid 

modernization.62 7

8

9 While smart grid investments are demonstrably capable of providing operational benefits to 

10 electric grid stakeholders, uncertainty and costly systems integration efforts are dissipating an 

11 unacceptable portion of the potential gains. Testing and certification programs “mostly exist 

12 in order to deal with failures caused by asymmetric information” [113]. They can help 

13 quantify the interoperability of prospective solutions, informing stakeholders of relative

14 costs, reducing uncertainty, and rewarding vendors that work to reduce systems integration 

15 costs with additional business. Firms that are unable or unwilling to pursue strategies that 

16 meet implementers needs for lower integration costs through greater interoperability will 

17 encounter a competitive disadvantage as these costs are brought into the light. In the long 

18 run, the informational improvements offered by third-party testing and certification programs 

19 will reduce the influence of actors whose lack of interoperability dissipates value [114].

20

21 While third-party testing and certification programs are not silver-bullet solutions for 

22 improving interoperability, thoughtful design and expansion of such institutions will be net23 beneficial to grid modernization. Past experience argues for the presence of five features that 

24 support reliable third-party certification programs: consumer demand, brand competition, 

25 interdependence, concentration of market power, and consumer vigilance [115]. These 

26 prerequisites are largely satisfied in the market for smart grid interoperability testing and 

27 certification services. However, efforts to improve outcomes may want to focus on areas 

28 where these prerequisites are not always met in full.

29

30 The following discussion explores a number of challenges that testing and certification 

31 programs must overcome to remedy information asymmetry, and reasons that these potential 

32 pitfalls should ultimately prove surmountable.

33

34 4.4.1 Challenge: consumer demand

35

36 Grid modernization will require massive expenditures by thousands of utilities and a rising 

37 group of service providers. Therefore, there will likely be sufficient consumer (in this case, 

38 utility and service provider) demand for third-party certification of the many systems that are 

39 envisioned to constitute the smart grid of tomorrow. The need for these services should 

40 induce entry into the certification market, especially if certification becomes either a 

41 regulatory or procurement requirement.

62 An example of investment constrained by imperfect information or information asymmetries are the numerous rejections 

by state regulators of utility applications for deploying smart meters [112].
59

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1 4.4.2 Challenge: interdependence and accountability

2

3 Market spoilage can occur when poor quality products or services persist long enough to 

4 affect customer value perception. In a testing and certification environment, certifications 

5 that do not adequately guarantee interoperability can affect not only the reputation of the 

6 certification agency, but left unchecked could damage the opportunities for competing firms 

7 as customer expectations decline.

8

9 The nature of ensuring interoperability between diverse systems means testing and 

10 certification programs most likely enjoy a sufficient degree of interdependence to hold each 

11 other accountable for poor performance. If the certifications provided by one firm prove 

12 unreliable to others in the process of providing upstream or downstream certification, these 

13 third-party certifiers will have an incentive to discipline the bad actors.

14

15 4.4.3 Challenge: concentration of market power

16

17 Large numbers of firms acting in diverse regulatory and economic regimes rais the expense 

18 and complexity for achieving accountability, regardless of the objectives [116]. While many 

19 firms operate in the electric power sector, market power can be concentrated for certain 

20 functions. For testing and certification, the concentration of market power within a relatively 

21 few organizations makes enforcement of the above described discipline necessary to achieve 

22 accountability less costly and more credible.

23

24 4.4.4 Challenge: consumer vigilance

25

26 The critical nature of the business of electric utilities virtually assures the customer vigilance 

27 necessary to make testing and certification programs successful. If poor certification services 

28 are responsible for electric service outages, utilities will find out and action will be taken to 

29 prevent further interruption to a sector that is a fundamental input to the modern economy 

30 and is substantially compensated based upon service reliability. Any third-party testing and 

31 certification programs that develop a reputation for failing stakeholders will undoubtedly be 

32 eliminated by market forces.

33

34

35 4.5 Interoperability Benefits

36

37 Grid modernization benefits will be substantial and sweeping. Interoperability is 

38 foundational to ensuring that new technologies can be cost-effectively integrated with the 

39 legacy system. It is also foundational to ensuring that diverse, distributed, and decentralized 

40 stakeholder groups can realize the anticipated benefit streams of grid modernization.

41

42 4.5.1 Minimizing transaction costs

43

44 Transaction costs are the costs of running an economic system, and high transaction costs are 

45 known to impede or completely block the formation of markets [117]. The ongoing rise of 

46 modular and distributed generation and delivery technologies has brought with it an emphasis 
60

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1 on employing aggregates and composites of these systems for integration with the electric 

2 power system. One consequence of this modularity and combinatorial innovation is that 

3 transaction costs increasingly constitute system level production costs. Greater 

4 interoperability will drive down transaction costs for the electric power sector, thereby 

5 allowing the creation of new market opportunities to obtain value for system stakeholders.

6

7 Improvements to technical and organizational interoperability will enable the dynamic 

8 assembly and reconfiguration of optimal value chains in accordance with changing 

9 conditions, opportunities, and threats to operation. The subsequent increase in available 

10 options and improvement in flexibility will drive efficiency gains in the dispatch of 

11 generation, transmission, and distribution segment assets in service of customer needs.

12

13 Interoperability will place downward pressure on information, integration, coordination, and 

14 transaction costs, opening up new value propositions. Some resource pairings for which 

15 coordination would presently prove uneconomic will — through greater interoperability and 

16 improved cost structures — be able to serve customers more frequently, leading to higher 

17 capacity utilization. Rising trading volume in services provided between increasingly 

18 interoperable nodes of the grid can fortify thin markets and provide liquidity that is attractive 

19 to other potential market participants. The presence of a virtuous cycle between new entry 

20 and market liquidity may further accelerate grid modernization.

21

22 The fall in transaction costs will lead less efficient combinations of resources to be foregone 

23 to the benefit of operators and their customers. Some resources that might otherwise have 

24 been rendered obsolete will be able to continue providing services due to the improved 

25 marketability of their offerings that comes with lower transaction costs. Old assets may also 

26 be repurposed in line with the changing requirements of grid operators and those they serve. 

27 By extending the useful life of the existing generation fleet and delivery assets, construction 

28 of new resources for which capacity utilization is expected to be low may be avoided.

29

30 Lower transaction costs will also enable smaller distributed resources to compete in the 

31 provision of energy and ancillary services, which could induce an accelerated pace of 

32 adoption for these emerging technologies. With time, such decentralization may reduce the 

33 criticality of any individual asset contributing to the grid, improving the resilience of the grid 

34 against diverse hazards. A grid with more options from which operators may choose could 

35 realize lower production costs while proving to be more reliable.

36

37 4.5.2 Creating value

38

39 To the extent that greater interoperability can reduce the cost of integrating new systems with 

40 the existing grid, modernization efforts may unleash new opportunities for sales growth. 

41 Electric vehicles are one clear opportunity for the electric grid to achieve growth through 

42 improving interoperability with increasingly ubiquitous transportation assets. 

43 Interoperability enhancements that improve observability and control of electric vehicle 

44 charging will make it operationally easier and more profitable for utilities and service 

45 providers to coordinate grid assets to meet customer needs.
61

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1 Greater interoperability can also encourage flexibility among electricity consumers. For 

2 most of the electric power sector’s history, customers were relatively unresponsive to the 

3 fluctuating cost of serving a load because the price paid by most consumers was static and 

4 did not reflect underlying costs. Interoperability enhancements can reduce the transaction 

5 costs associated with dynamically communicating information on operating costs and 

6 conditions to relevant stakeholders, and therefore increase the price responsiveness of end 

7 customers. These relatively elastic consumers will be better equipped to shift their 

8 consumption patterns to account for price variability, which will improve capacity utilization 

9 for existing generation assets [118].

10

11 The opportunities for the exercise of market power by generation owners also falls with the 

12 increasingly elastic demand interoperability engenders. Prices will therefore move towards 

13 competitive equilibrium levels as interoperability improves.

14

15 4.6 Conclusion and Future Work

16

17 With more than 3,000 utilities in the United States, the importance of interoperability to the 

18 utility, marketplace, and customer cannot be overstated. While specific requirements and 

19 functions will always be made at the local level, as the rollout of any given investment will 

20 not be uniform across the country or state, a foundation of interoperability and open 

21 standards provides the building blocks for successfully meeting system needs.

22

23 Interoperability is a key component of ensuring the technical and economic benefits from 

24 grid modernization flow across stakeholder interests throughout the evolution of the 

25 electricity system. Utilities are investing in substantial updates to their infrastructure, and 

26 customers are increasingly seeking to achieve additional savings and benefits from 

27 investments in DER. Interoperability driven by open standards can help lower transaction 

28 and implementation costs associated with DER and other investments.

29

30 Interoperability provides benefits that are often lost in the larger context of a utility rate case. 

31 However, investments without consideration of interoperability will limit the ultimate reach 

32 of a technology, may be more expensive than necessary, and may not enable a grid that is 

33 ready and capable of integrating and optimizing the new resources coming to the distribution 

34 system. The costs associated with the absence of interoperability are growing as our 

35 distribution systems become more advanced and customers seek to realize greater savings 

36 from their investments. Effective testing and certification programs will assist in showing 

37 these savings, but regulators should ensure that interoperability is an identified component of 

38 any utility investment.
62

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1

2 5 Cybersecurity

3

4 In the traditional electrical grid power flows in one direction — from centralized generation 

5 facilities, through transmission lines, and finally to the customer via distribution utilities. As 

6 electric utilities incorporate new technologies and accommodate changing customer 

7 expectations, the basic structure of the grid remains broadly consistent with the first electric 

8 systems built more than a century ago. The centralized design has historically brought 

9 efficiencies in facilities and operations, but the criticality of centralized assets has also made 

the grid vulnerable to both malicious actions and natural disasters.63 10 

11

12 As demands on the power system evolve and come in conflict with the physical constraints 

13 of decades-old infrastructure, the operational and economic solutions brought by new 

14 technologies gain prominence. While the distributed nature of many new technologies 

15 diminishes the criticality of any single asset, the informational capabilities inherent to these 

devices carry vulnerabilities that were unknown to the historical grid.64 16 

17

63 For example, the Northeast Blackout of 2003 affected 50 million people and was initiated when a grid operator was 

unable to respond to the failure of the Eastlake Unit 5 generator and the Stuart-Atlanta 345 kV transmission line in Ohio 

[119]. 64 Grid communications are increasingly based on conventional “Information Technology (IT)” approaches, leaving them 

more vulnerable to attacks from hackers with IT expertise.

Key Messages – Cybersecurity

New technologies, changing resources, and expanding stakeholder participation carry with 

them a growing cybersecurity risk. To realize the benefits of an interoperable smart grid, 

security practices will have to evolve beyond strategies of physical isolation or other overly 

restrictive access regimes.

Understanding and mapping institutional cybersecurity capabilities and processes to the 

outcomes we seek in a smart grid will help an organization position itself to manage 

cybersecurity requirements at the device or interface level. The Cybersecurity Risk Profile 

for the Smart Grid presented in this section provides a structured approach to assessing 

organizational readiness for cybersecurity.

Cybersecurity protections at the device or system level need not be newly invented even as 

new technologies and interfaces are introduced to the system. New interface characteristics 

can be mapped to the existing set of logical interface categories, thereby facilitating 

protection through known standards and best practices likely already employed for other 

legacy system interfaces. 
63

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1 The large number of non-utility stakeholders and increasing number of devices connected to 

2 the grid means that — even in the best of circumstances — secure operations can no longer 

3 be guaranteed by a single organization or security department. The utility must instead rely 

on engineering strategies65 and cybersecurity risk management and mitigation techniques66 4 to 

5 better ensure secure operation. Furthermore, the integration of modern technology with 

6 legacy infrastructure via custom-designed interfaces and unique feature-sets can complicate 

7 vulnerability assessments and exacerbate the challenge of protecting power systems.

8

9 Protecting the electrical grid against cyber-attack also carries a set of constraints that 

10 precludes use of some common IT security strategies. For example, when an IT system is 

11 under attack best practice often involves quickly disconnecting or otherwise isolating 

12 affected devices from the network, but that approach may not be possible in power system 

13 operations where hastily disconnecting control systems could trigger blackouts or other 

14 catastrophic system failures. 

15

16 Securing the grid can seem an impossible challenge given the extensive diversity of 

17 organization, actor, and equipment, but cybersecurity issues are not insurmountable and can 

18 be mitigated. A successful approach to cybersecurity consists of many techniques that 

19 involve processes as well as technology solutions. Minimizing organizational and device 

20 exposure to threats promotes system security but requires a structured approach to 

21 characterizing cybersecurity risks and managing the system’s protection and recovery 

22 schemes.

23

24 The complexity of achieving cybersecurity stems from the fact that no single action can 

25 ensure systemwide security. Much like the smart grid, where new system-level capabilities 

26 are most often realized through the aggregated impact of many discrete investments and 

27 technology choices, achieving cybersecurity requires utilities to address a wide-ranging set of 

28 issues from general IT policies to techniques used to secure specific physical assets and 

29 interfaces.

30

31 A structured approach to assessing cybersecurity risk is critical to appropriately prioritizing 

32 actions that will have the greatest impact on securing the utility and its assets. Below we 

33 describe approaches to assessing organizational risk through the application of the NIST 

34 Framework for Improving Critical Infrastructure Cybersecurity [120] and evaluating the new 

35 interfaces and associated cybersecurity requirements introduced by emerging system 

36 architectures.

65 For example, system configurations that rely on gateways, network segmentation, and security perimeters. 66 For example, those described in the NIST Cybersecurity Framework core and including authentication, access control, 

key management, network monitoring, and security logs.
64

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1 5.1 Securing Organizations

2

3 The modern electrical grid should be safe, reliable and resilient, yet cybersecurity threats 

4 have exploited the increasing complexity and connectivity of this critical infrastructure [121, 

5 122]. A resilient grid must therefore withstand cyber events in addition to the known 

6 hazards, human errors, hardware failure, and software bugs that occur in the system. The 

7 NIST Framework for Improving Critical Infrastructure Cybersecurity (the Cybersecurity 

8 Framework) is a key part of a systemic process organizations can use to identify, assess, and 

9 manage cybersecurity risk. Through this process, utilities and other grid organizations can 

10 prioritize those activities that can best manage cybersecurity-related risk while aligning with 

11 their unique environment, requirements, and budgetary considerations.

12

13 The Cybersecurity Framework consists of three main components: 

14

Cybersecurity Framework Core67 15 – Provides a catalog of desired cybersecurity 

activities and outcomes68 16 using common language. The Core guides organizations in 

17 managing and reducing their cybersecurity risks.

18

19 Framework Implementation Tiers – Provide context on how to view cybersecurity 

20 risk management, and help organizations assess the functionality and repeatability of 

21 their risk management process.

22

23 Framework Profiles – Used to identify and prioritize opportunities for improving 

24 cybersecurity at an organization through customization of Core outcomes.

25

26 5.1.1 NIST cybersecurity framework core functions

27

28 The Cybersecurity Framework Core is built around five concurrent and continuous Functions 

29 used to analyze an organization’s entire risk management portfolio. When considered 

30 together, these five Functions provide a high-level, strategic view of the organization’s

31 cybersecurity risk management approach. The five cybersecurity functions are:

32

33 Identify – Develop the organizational understanding to manage cybersecurity risk of 

34 its systems, assets, data, and capabilities. The activities in the Identify Function are 

35 foundational to an organization’s assessment of cybersecurity risks and allow 

36 organizations to focus and prioritize their cybersecurity efforts consistent with its risk 

37 management strategy and business needs.

38

39 Protect – Develop and implement the appropriate safeguards to ensure delivery of 

40 critical infrastructure services. The activities in the Protect Function support the 

41 ability to defend against a potential cybersecurity event and limit or contain its 

42 impact.

67 Elements of the Cybersecurity Framework – including Core, Implementation Tiers, Profile, Function, Category, and 

Subcategory – are normally capitalized and will be capitalized throughout this document. 68 The word “outcomes” is used because the Cybersecurity Framework focuses on the “what” not the “how.” In other 

words, the emphasis is on the cybersecurity outcomes that the organization wants to achieve, but not how they will achieve 

them.
65

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1 Detect – Develop and implement the appropriate activities to identify the occurrence 

2 of a cybersecurity event. The activities in the Detect Function enable timely 

3 discovery of cybersecurity events.

4

5 Respond – Develop and implement the appropriate activities to take action regarding 

6 a detected cybersecurity event. The activities in the Respond Function support the 

7 ability to limit and contain the impact of a potential cybersecurity event.

8

9 Recover – Develop and implement the appropriate activities/plans to maintain 

10 resilience and restore any capabilities or services that were impaired due to a 

11 cybersecurity event. The activities in the Recover Function support timely recovery 

12 to normal operations to reduce the impact from a cybersecurity event.

13

14 These Functions align with existing methodologies for incident management and help 

15 elucidate the benefits of cybersecurity investments. When considered together, the Functions 

16 provide a high-level, strategic view of the lifecycle and management of cybersecurity risk 

17 within an organization, and provides a structured approach to evaluating cybersecurity 

18 outcomes.

19

20 5.1.2 NIST cybersecurity framework core categories and subcategories

21

22 The Cybersecurity Framework organizes the five cybersecurity Functions (Identify, Protect, 

23 Detect, Respond, and Recover) into subdivisions, or Categories, that can be used to group 

24 similar cybersecurity activities that support a particular Function. Table 4 shows the five 

25 Functions divided into the 23 Categories of cybersecurity activities. 
66

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1

2

3 The Cybersecurity Framework provides an additional level of granularity by further dividing 

4 the 23 Categories of cybersecurity activities into 108 Subcategories, each defining a desired 

5 outcome. These Subcategories provide a list of outcomes that — if achieved — would 

6 increase the likelihood that an organization could successfully optimize its cybersecurity 

7 posture relative to its risk tolerance. Table 5 provides an example of two Cybersecurity 

8 Framework Subcategories aimed at managing supply chain risk within the Identify Function.

Table 4 – Cybersecurity Framework functions and categories
67

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1 Table 5 – Cybersecurity Framework subcategory examples

Function Category Subcategory Informative References

Identify 

(ID)

Supply Chain Risk 

Management 

(ID.SC):

The organization’s 

priorities, constraints, 

risk tolerances, and 

assumptions are 

established and used to 

support risk decisions 

associated with 

managing supply 

chain risk. The 

organization has 

established and 

implemented the 

processes to identify, 

assess and manage 

supply chain risks.

ID.SC-1: Cyber supply chain 

risk management processes are 

identified, established, assessed, 

managed, and agreed to by 

organizational stakeholders

CIS CSC 4

COBIT 5 APO10.01, APO10.04, APO12.04, 

APO12.05, APO13.02, BAI01.03, BAI02.03, 

BAI04.02

ISA 62443-2-1:2009 4.3.4.2

ISO/IEC 27001:2013 A.15.1.1, A.15.1.2, 

A.15.1.3, A.15.2.1, A.15.2.2

NIST SP 800-53 Rev. 4 SA-9, SA-12, PM-9

ID.SC-2: Suppliers and third 

party partners of information 

systems, components, and 

services are identified, 

prioritized, and assessed using a 

cyber supply chain risk 

assessment process

COBIT 5 APO10.01, APO10.02, APO10.04, 

APO10.05, APO12.01, APO12.02, 

APO12.03, APO12.04, APO12.05, 

APO12.06, APO13.02, BAI02.03

ISA 62443-2-1:2009 4.2.3.1, 4.2.3.2, 4.2.3.3, 

4.2.3.4, 4.2.3.6, 4.2.3.8, 4.2.3.9, 4.2.3.10, 

4.2.3.12, 4.2.3.13, 4.2.3.14

ISO/IEC 27001:2013 A.15.2.1, A.15.2.2

NIST SP 800-53 Rev. 4 RA-2, RA-3, SA12, SA-14, SA-15, PM-9

2

3

4 The final element of the Cybersecurity Framework are the informative references provided 

5 next to each subcategory. As shown in Table 5, these references are specific sections of 

6 standards, guidelines, and practices common among critical infrastructure sectors that 

7 provide practical suggestions for how to achieve the desired outcomes for each Subcategory. 

8 Based upon cross-sector guidance received during the Cybersecurity Framework 

9 development process and therefore not explicitly related to power sector activities, the 

10 informative references provide a launchpad for users seeking to gain knowledge on existing 

11 guidelines and best practices for achieving the cybersecurity subcategory outcomes.

12

13 The Cybersecurity Framework Core is available online in an easily accessible spreadsheet 

14 format [123].

15

16 5.1.3 Cybersecurity profiles

17

18 Creating a Cybersecurity Profile translates the outcomes of the Cybersecurity Framework 

19 Core into a prioritized set of actions an organization can use to better position itself against 

20 cyber threats. This process aligns the Cybersecurity Framework Functions, Categories, and 

21 Subcategories with the organization’s business requirements, risk tolerance, and resources.

22

23 The prioritization of the Subcategory outcomes will vary from one organization to the next 

24 because each organization has unique requirements including risk tolerance and budge. It is 

25 this prioritization that is the essence of a Profile.

26

27 A great benefit of a Cybersecurity Framework Profile is that it provides a common language 

28 to communicate requirements among interdependent stakeholders responsible for the 

29 delivery of essential critical infrastructure products and services [120]. Similar to the 
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1 ontology provided in this Framework (see Section 2.3), the comprehensive considerations of 

2 a Cybersecurity Framework Profile offer organizations and their partners a language and 

3 methodology to help ensure new products or services meet critical security outcomes. This is 

4 especially important in the electrical grid, where power system owners and operators rely on 

5 and interact with an ever-increasing community of active participants and third-party service 

6 providers. 

7

8 5.1.4 Cybersecurity framework profile for the smart grid

9

10 To facilitate development of a common cybersecurity language and methodology for the 

11 power sector, NIST created a cybersecurity risk Profile for the smart grid (Smart Grid 

12 Profile) based upon the Cybersecurity Framework [124]. In the Smart Grid Profile, the five 

13 cybersecurity functions are examined through the lens of power system owner/operators, and 

14 cybersecurity outcomes are evaluated for relevance against the following four high-level 

15 business objectives:

16

17 Maintain safety: Safety is an overarching concern of power system management 

18 seeking to minimize the impact to human life, equipment, and the environment from 

19 cybersecurity risks.

20

21 Maintain power system reliability: Reliability is the ability to deliver stable and 

22 predictable power in expected conditions or, in case of power system failure, the 

23 ability to restore normal operational service.

24

25 Maintain power system resilience: Resilience is the ability of power systems to 

26 withstand instability, unexpected conditions or faults, and gracefully return to 

27 predictable, but possibly degraded, performance.

28

29 Support grid modernization: This requirement supports integration of smart 

30 technologies with the traditional grid by managing cybersecurity risks to power 

31 systems, including integrity and timeliness of data and control commands.

32

33 The Smart Grid Profile is designed to be broadly applicable to the electricity sector and is 

34 intended to help power system owners/operators prioritize cybersecurity activities based on 

35 the high-level business objectives described above. As shown in Figure 17, the Profile also 

36 describes considerations for each Subcategory which highlight challenges that may be 

37 encountered as organizations attempt to achieve the Subcategory outcomes.

38

39 The list of cybersecurity considerations for power system owner/operators is one of the most 

40 valuable components of the Smart Grid Profile. These context-specific descriptions of issues 

41 relevant to the desired cybersecurity outcomes of the Core yield an accessible baseline of 

42 language and understanding about power system cybersecurity. It is hoped this common 

43 foundation will improve dialogue across stakeholder communities regarding cybersecurity 

44 risks, mitigation strategies, and investments. 
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1 Function (ID) Identify

2 Category (AM) Asset management

3 Subcategory (1) Physical devices and systems within the organization are 

4 inventoried

5 Subcategory (2) Software platforms and applications within the organization are 

6 inventoried

7

8

9 Figure 17 – Example of cybersecurity Considerations for the electrical system

10

11 The ubiquitous nature of an electric grid on which all of modern society depends combined 

12 with the broad-reaching nature of the grid operator objectives previously described yield a 

13 Smart Grid Profile in which most Subcategories are deemed relevant to one or more of the 

14 business objectives. While this lack of meaningful differentiation among Subcategories 

15 would provide little value to an organization attempting to prioritize security investments, 

16 several benefits accrue to industry from this effort. 

17

18 First and foremost, the Smart Grid Profile describes power system-relevant Considerations 

19 for each cybersecurity Subcategory in the Cybersecurity Framework. This baseline of issues 

20 related to grid cybersecurity provides a common reference language upon which

21 cybersecurity discussions can be had and gives a shared context for establishing 

22 cybersecurity requirements and investments. The easily accessible outcomes and 

23 considerations of the Profile can smooth interaction across organizations or stakeholder 

24 communities, including with state regulators who are often charged with approving utility 

25 cybersecurity investments. 

26

27 Another benefit of a Smart Grid Profile — in which the significant majority of cybersecurity 

28 outcomes are relevant to each of the examined objectives — is the insight gained from the 

29 few instances where Framework Subcategories were not deemed relevant to most or all of the 

30 examined objectives. Given the broad nature of objectives evaluated for this Profile, a 

31 universal determination of non-relevance may indicate a structural constraint that is unique to 

32 the power sector.
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The PR.AC-669 1 Subcategory is an excellent example of how a Profile can highlight the 

2 interplay between important cybersecurity outcomes and system constraints. The outcome 

3 for PR.AC-6 is that identities are proofed, bound to credentials, and asserted in interactions. 

4 Yet the Smart Grid Profile does not prioritize PR.AC-6 as a cybersecurity outcome relevant 

5 to grid operator objectives (see Figure 18).

6

7 Function (PR) Protect

8 Category (AC) Identity management, authentication and access control

9 Subcategory (6) Identities are proofed and bound to credentials and asserted in 

10 interactions

11

12

13 Figure 18 – Smart Grid Profile excerpt

14

15 Identity proofing is a well-known contributor to system-level cybersecurity, and a host of 

16 well-regarded best practices exist to achieve that capability [125], so the designation of this 

17 cybersecurity outcome as not relevant to the grid should be viewed skeptically. Further 

18 examination of the Profile considerations for the PR.AC-6 subcategory indicates the mutual 

19 assistance strategies employed by utilities following natural disasters and other significant 

20 disruptions present a structural constraint against achieving this outcome through 

21 conventional identity proofing and credentialing approaches. In short, requiring identities be 

22 proofed and bound to credentials prior to interacting with the system would inhibit a utility’s 

23 ability to recover from major disruptions. 

24

25 A consequence of the structural constraint to achieving the cybersecurity outcome in PR.AC26 6 is that utilities will have to devise alternate strategies for controlling access to systems and 

27 devices. Utilities will also have to address any risks that may be introduced by an alternate 

28 credentialing and access control scheme. The identity management, credentialing, and access 

29 considerations for utilities will evolve with the system’s architecture, and will become more 

30 complex as autonomous devices owned by organizations other than the utility play ever31 increasing roles in system operations.

69 This notation indicates this is the sixth Subcategory for the Identity management, authentication, and access control (AC) 

Category under the protect (PR) Function of the Cybersecurity Framework.
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1 The full set of Smart Grid Profile Considerations is described in [124] and duplicated in 

2 Appendix G – Smart Grid Cybersecurity Profile Subcategory Prioritization and 

3 Considerations Matrices. The original Smart Grid Profile publication also includes a 

4 mapping of the NERC Critical Infrastructure Protection (CIP) v5 regulations to the 

5 Cybersecurity Framework v1.0 Subcategories (see Section 5.3).

6

7

8 5.2 Securing Information Exchange

9

Information cybersecurity is primarily associated with information exchange interactions70 10

between entities71 11 and is a critical aspect of power system operations and security. The 

12 impacts of cybersecurity breaches — whether deliberate or inadvertent — may affect both 

13 physical and cyber operations of the grid.

14

15 5.2.1 Known system interfaces and categories

16

Identifying the entities71 17 involved with information exchanges in power systems operations is 

18 the first step towards understanding cybersecurity issues for the grid. To facilitate this 

19 understanding, the 2014 NIST publication Guidelines for Smart Grid Cybersecurity (NISTIR 

20 7628) [126] included a composite diagram of grid entities that exchange information within 

21 and across each of the seven smart grid Conceptual Model domains (see Section 2.1 and 

22 Appendix A – Smart Grid Conceptual Model Domains). By mapping these information 

23 exchanges — called logical interfaces — to the composite diagram of grid entities, the 

24 guidelines found in NISTIR 7628 described where, at a high level, the smart grid would need 

25 to provide security (see Figure 19).

70 Although information cybersecurity also addresses stored data, NIST’s smart grid program focus is on interoperability and 

securing associated information exchanges. 71 Entities consist of—but are not limited to—users, systems, devices, network or communications nodes, etc.
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1

2 Figure 19 – Logical Interface Reference Model "Spaghetti Diagram" from NISTIR 7628

3 Yet knowing where security is needed is of limited value, as location information alone does 

4 not provide details on the requirements of what needs to be done to enhance security. To 

5 understand the latter, the NISTIR 7628 [126] defined a set of logical interface categories 

6 (LICs) based on attributes that could affect grid cybersecurity requirements.

7

8 Because many of the individual logical interfaces have similar security-related 

9 characteristics, grouping interfaces into LICs with similar characteristics is a means to 

10 simplify the identification of appropriate security requirements. In that way, the hundreds of 

11 individual interfaces drawn in Figure 19 can be grouped into 22 representative LICs, from 

12 which broadly applicable cybersecurity requirements can be derived (see Appendix H –

13 Logical Interface Categories from NISTIR 7628).

14

15 5.2.2 New system interfaces

16

17 The modern grid will be more heavily dependent on information exchange than the legacy 

18 grid. As DERs and other innovations are used more extensively across the grid (see Section 

19 2.2.3), the set of entities involved with information exchanges in power system operations 

20 will expand and new communications interfaces will evolve. It is useful, therefore, to 

21 explore how portions of the Figure 19 logical interface diagram — which contains high-level 
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1 representations of current power system operations domains—can be expanded to provide 

2 more detailed cybersecurity requirements for emerging interfaces.

3

4 To explore the cybersecurity implications of introducing new technologies and architectures 

5 to the grid, we updated the NISTIR 7628 logical interface diagram found in Figure 19 to 

6 include examples of the new equipment and information exchanges that could be expected 

7 for future High-DER penetration grids. A representation of the new power system entities 

8 and logical interfaces for a High-DER architecture is shown in Figure 20, where Uxx-labeled 

9 blue interface arrows are the same as those originally shown in NISTIR7628 and Dxx10 labeled red interface arrows are newly introduced interfaces for the High-DER example.

11

12 From the High-DER example shown in Figure 20, we understand that a modernized grid 

13 would likely have to accommodate at least three new types of communications interfaces, 

14 including:

15

16 New interfaces for new entities: As new entities are introduced to the grid the 

17 number of communications interfaces and pathways will increase dramatically. For 

18 example, extensive penetration of distributed resources requires introduction of a 

19 Distributed Energy Resource Management System (DERMS) into the grid operations 

20 domain (Figure 20, box 25). This DERMS would likely have different data and 

21 communications requirements than legacy systems, and new communications 

22 linkages are required throughout the rest of the system.

23

24 New interfaces between subsystems: As the physical capabilities of grid-connected 

25 systems advance, logical interface requirements between equipment subsystems will 

26 evolve. The customer-sited DER asset, electric vehicle asset, and the utility-scale 

27 DER or cogeneration asset have been split to reflect the different logical interface 

28 requirements between asset controllers (Figure 20, boxes 4a, 4c, and 6a) and the 

29 equipment (Figure 20, boxes 4b, 4d, and 6b) connected to the grid physically 

30 consuming or supplying electrons.

31

32 New interfaces for legacy systems: As new capabilities are introduced to 

33 conventional grid assets, information will have to be exchanged with and between 

34 legacy systems. Both the utility-scale DER or cogeneration asset and the facility 

35 energy management system interface directly with the utility supervisory control and 

36 data acquisition (SCADA) system via a new logical interface (Figure 20, red lines 

37 D03 and D04). Additionally, where Aggregator interfaces in NISTIR 7628 were 

38 constrained to energy providers and markets (Figure 19, box 41b and blue lines U20 

39 and Uaa), Aggregators interact with new actors in the High-DER scenario and the 

40 logical interfaces increase accordingly (Figure 20, red lines D08, D52, and D92). 
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1

Figure 20 – Example logical interfaces in a High-DER architecture72 2

3

4 5.2.3 Assessing security requirements of new interfaces

5

6 New or changed logical interfaces may require new cybersecurity precautions. The High7 DER example identifies nearly a dozen new interfaces (Figure 20, thin red lines), and the 

8 changing characteristics of the system itself may alter the communications and cybersecurity 

9 requirements for previously established interfaces.

10

11 To assess the cybersecurity requirements for the High-DER example, the new and updated 

12 interfaces were evaluated against the LICs found in NISTIR 7628. Each of the new 

13 interfaces for High-DER example could be mapped to an existing LIC, meaning the 

14 cybersecurity requirements for protecting communications interfaces within this new 

15 architecture can be derived — at least in part — from those described in the current NISTIR 

16 7628. 

17

18 The complete evaluation of each information exchange in Figure 20 is provided in 

19 Appendix I – Types of Information Exchange Between Entities in the High-DER Example, 

72 To ease examination, this figure includes only those entities requiring new logical interfaces for this high-DER example.
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1 and the LIC interface mapping is shown graphically in Figure 21. It should be noted, 

2 however, that not all of the conventional approaches for responding to and coping with 

3 cybersecurity attacks that were described in NISTIR 7628 will map directly to evolving grid 

4 architectures. 

5

6 For example, the High-DER scenario depicts a power system that relies on increasing 

7 communications between, and coordinated management of, diverse assets to provide 

8 essential grid services. As the criticality of DERs to system operations increase, it may not 

9 be plausible to abort communications and potentially cease device operations in response to 

10 cyberattacks as was described in NISTIR 7628 for several LICs in conventional system 

11 architectures. Even so, mapping emerging interfaces to existing LICs and the associated 

12 NISTIR 7628 cybersecurity guidance provides a foundation upon which the cybersecurity of 

13 emerging grid architectures can be built.

14

15

16 Figure 21 – Logical interface categories (LICs) for the High-DER example
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1 5.3 Additional Cybersecurity Resources

2

Cybersecurity requirements for the Nation’s high-voltage transmission system73 3 are overseen 

4 by the Federal Energy Regulatory Commission (FERC), and developed and enforced by the 

5 North American Electric Reliability Corporation (NERC) through a series of Critical 

6 Infrastructure Protection (CIP) standards [127]. From the adoption of its first cybersecurity 

7 standard in 2004 [128], NERC CIP has evolved into a collection of current and future 

8 standards subject to enforcement [129].

9

10 While the CIP standards provide detailed and regularly updated cybersecurity requirements 

11 for transmission system stakeholders, enforcement of these standards is constrained to the 

bulk electric system74 12 (BES) and there is no nationwide analog for distribution grids. While 

13 FERC engages state and industry partners to address cybersecurity issues through voluntary 

14 initiatives, the Commission does not have authority to directly impose cybersecurity 

15 obligations on entities outside FERC’s BES jurisdiction [130].

16

17 Analysis of realistic potential failure scenarios provides insight into common cybersecurity 

18 threats, vulnerabilities, and mitigations. By also characterizing the potential impacts of a 

19 cyber event, scenario analysis can be useful for a range of organizational responsibilities 

20 from risk assessment to security testing. The National Electric Sector Cybersecurity 

21 Organization Resource [131], led by the Electric Power Research Institute (EPRI) with 

22 funding from DOE, has defined a set of cybersecurity failure scenarios that span each of the 

23 NIST Smart Grid Conceptual Model domains and is a useful complement to requirements24 and standards-driven cybersecurity processes [132].

25

26 The Cybersecurity Framework and NISTIR 7628 have been recognized as useful tools for 

27 characterizing and reducing cybersecurity risk [127, 130, 132], but no single document or 

28 organization can provide a comprehensive understanding of the cybersecurity risks and best 

29 practices that must be addressed throughout the power system. The valuable resources 

30 described in this section and elsewhere are each unique in scope and purpose, and provide 

31 complementary information and guidance on cybersecurity practices.

32

33 NIST and collaborators have developed numerous analyses to help clarify and map the 

34 alignment between these and other cybersecurity guidance documents and standards. Of 

35 particular interest has been alignment between the Cybersecurity Framework and NERC CIP, 

36 and mappings between the two have been published for two versions of the CIP standards 

37 [133].

38

39 Effective cybersecurity guidance must be regularly updated, and both the NIST 

Cybersecurity Framework and the NERC CIP standards have been updated75 40 since the initial 

41 mapping effort in 2014. NIST and NERC have collaborated on an updated mapping of the 

42 Cybersecurity Framework v1.1 to the latest CIP standards. This mapping will soon be posted 

73 Transmission elements or power sources operating at 100 kV or higher are considered high-voltage. 74 The high-voltage transmission system is commonly referred to as the bulk electric system. 75 NIST Cybersecurity Framework has been updated to version 1.1 [120], and some NERC CIP standards are in their eighth 

revision while others are just being introduced [129].
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1 to a NERC website (and linked to from a NIST website) and published in a forthcoming 

2 NIST report. NIST has also completed a mapping of the Cybersecurity Framework v1.1 to 

3 the EPRI failure scenarios for advanced metering infrastructure, distributed energy resources, 

4 and distribution grid management [132], which will be published in the same NIST report.

5

6

7 5.4 Conclusions and Future Work

8

9 The smart grid brings new information technology capabilities to electric infrastructure, and 

10 as this occurs the number of communications interfaces will grow substantially. No single 

11 mitigation method can guarantee security and organizations will be best served by taking 

12 complementary approaches to assess and manage risk at multiple levels within the system. 

13

14 Even as the number of communication interfaces grows, the fundamental cybersecurity 

15 requirements for each interface – and the attendant obligations on their managing 

16 organizations –are likely to be consistent with known requirements. This Framework 

17 describes two complementary approaches to risk management, one at the organizational level 

18 and the other at the device interface level.

19

20 Creation of a Cybersecurity Risk Profile for the Smart Grid (see Section 5.1.4) provides a 

21 structured methodology and common reference language for evaluating organizational 

22 cybersecurity posture while facilitating communication across organizational boundaries and 

23 smart grid domains. The description of grid-specific subcategory considerations allows 

24 utilities or other grid organizations to assess their own security posture and prioritize 

25 cybersecurity outcomes that best match their organizational need.

26

27 But complex infrastructures with multiple actors like the power system are difficult to fully 

28 characterize in a single Cybersecurity Profile. Utilities and other grid stakeholders may 

29 therefore choose to create multiple profiles to characterize cybersecurity outcomes for 

30 specific interactions, functions, or other organizing principles within the system. Multiple 

31 profiles can also be developed to examine differences between present and desired 

32 cybersecurity states, where the identified gaps can provide a foundation for an organization’s 

33 cybersecurity roadmap.

34

35 Examining the emerging set of logical interfaces as new technologies take root in the power 

36 system (see Section 5.2.2) provides some confidence that the basic cybersecurity 

37 requirements described by existing LICs will be relevant for new interfaces as well. 

38 However, it is similarly likely that cybersecurity response guidance may require updating to 

39 capture emerging functionality and system criticality of these technologies (see Section 

40 5.2.3). Mapping new interfaces to existing LICs should therefore facilitate the effective 

41 application of category-driven protection schemes to the evolving grid, and also identify gaps 

42 in this approach where updated cybersecurity guidelines and/or protection schemes would be 

43 useful.

44

45 While the Cybersecurity Risk Profile and interface category-driven risk management 

46 approaches are useful, the complexity inherent in crafting new Profiles or mapping LIC 
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1 protection schemes may require expertise not available to every organization. This 

2 complexity, combined with the manifold security requirements to which firms must adhere 

3 and the diversity of options available in the marketplace, can create a confusing environment 

4 for securing grid systems. This is why stakeholder feedback to NIST has repeatedly focused 

5 on the value of cybersecurity case-studies that can be used to create tangible implementation 

6 guides, as well as a need for updated mappings between the latest versions of cybersecurity 

7 requirements and analysis guidelines. 

8

9 As grid architectures evolve, so too will communications network architectures. The 

10 transition from brokered to brokerless communications, expanding use of publicly accessible 

11 tools and infrastructures, and increasing dynamism of customer participation with the system 

12 all indicate a need for improved identity management infrastructure for grid connected 

13 devices. 

14

15 Finally, interoperability in the system will only be achieved if openly available standards are 

16 used across many utilities and vendors. The use of open standards to achieve interoperability 

17 also means significant numbers of devices and systems will likely be more visible and 

18 potentially accessible to malicious actors than in the past. Interoperability requirements and 

19 standards must therefore include security requirements, including data protection and attack 

20 detection, and an ability to respond to the threat and recover from disruption
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1

2 6 Testing and Certification

3

4 The modern electric grid is often described as a “system of systems” (SOS) spanning 

5 multiple technology domains, involving thousands of organizations, and hundreds of 

6 standards (see Section 2.3). Smart grid devices, systems and applications require extensive 

7 data exchange and need well-defined interfaces to transfer and translate this data between 

8 points across the grid. Interoperability is necessary to provide seamless functional 

9 performance across systems that enables many benefits of the smart grid.

10

11 Test programs are needed to ensure products are developed in a manner where standards 

12 implementation enhances interoperability. While standards promote interoperability, the 

13 breadth and flexibility of implementation options for each standard means that 

14 interoperability is not guaranteed. Reducing the complexity involved with implementing a 

15 standard would also simplify the associated testing requirements to validate conformance and 

16 give a clearer indication of device or system capability upon certification.

17

18 This chapter provides an overview and benefits of testing and certification (T&C) for smart 

19 grid standards and describes benefits, gaps, and required work to address the longer-term 

20 implementation challenges in maintaining a robust T&C ecosystem for system and device. 

21 The development and use of Interoperability Profiles is proposed as a mechanism to advance 

Key Messages – Testing and Certification

Testing and certification is a critical enabler of grid modernization with benefits to industry 

ranging from operational trustworthiness to investor confidence. Yet the availability of 

testing and certification programs is limited.

Smart grid standards often include many user-selected options. This optionality typically 

allows for non-interoperability even among products conforming to the same standard. This 

means that the current industry focus on certifying conformance to individual standards is 

inadequate to assure interoperability.

Interoperability Profiles that describe the communications protocol and data model 

requirements necessary to achieve a specific set of physical functions are possible solutions to 

the interoperability challenge.

Interoperability profiles are not new standards, but instead describe a subset of requirements 

from existing standards that—when implemented and verified through testing and 

certification—would ensure interoperability across devices and systems.
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1 interoperability while simplifying evaluation requirements, thereby facilitating and further 

2 enhancing T&C efficiency and efficacy.

3

4 Interoperability Profiles (see Section 6.5.1) describe a subset of a standard — or group of 

5 standards — for implementation that would reduce the degrees of freedom available for 

6 implementing standards by the device supplier, implementor, and system owner. By 

7 clarifying interoperability functions, the interoperability profile would narrow performance 

8 gaps that hinder interoperability and streamline the set of device functions that must be 

9 evaluated for effective certification. 

10

11

12 6.1 The Role of Testing and Certification

13

14 Testing and Certification (T&C) programs provide common processes that are used to 

15 demonstrate conformance with a standard [134]. When accepted and used across industries, 

16 these testing and certification processes support interoperability between devices and systems 

17 that span equipment vintage and manufacturer. Completing a T&C program allows vendors 

18 to offer products certified to a standard, and affords customers a level of trust that products 

19 will work as intended when deployed.

20

21 Standardized interface and performance requirements are necessary for modernizing the grid 

22 as new technology integrates with legacy grid systems [135, 136]. Well-defined interface 

23 requirements enable creation of adaptors and gateways that allow new equipment to interact 

24 with existing systems to extend useable service life. Performance requirements are critical to 

25 ensure the deployed equipment has the necessary capability or can be upgraded to 

26 accommodate future applications.

27

28 The value of certification programs increases as the number of devices grows through 

29 economies of scale for both manufacturers and test program operators. As the range of 

30 technologies and their uses continue to evolve, grid operations become commensurately more 

31 complex. Certification programs, therefore, become essential to ensure the reliable 

32 performance of grid components in this increasingly dynamic environment.

33

34

35 6.1.1 Testing and certification value

36

37 As described in Section 4.3.5, the T&C value proposition benefits all grid stakeholders. The 

38 following list describes how these benefits accrue to principal classes of grid stakeholders:

39

Customers76 40 benefit by ensuring standards and performance requirements are 

41 implemented appropriately and consistently across purchased equipment, which eases 

42 integration of new products and services with existing infrastructure and operations 

43 [137].

76 Here the term “customers” is used to describe the individual or firm that purchases equipment. While a customer could be 

the electricity consumer who purchases appliances or other residential-scale smart grid technology, a customer could also be 

a utility that purchases equipment appropriate only for use on the bulk or distribution power systems.
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1 Manufacturers and Vendors benefit from the establishment of clear performance 

2 requirements, which reduces implementation costs for new standards [138]. T&C 

3 programs ensure product certification occurs in a neutral environment and creates a 

4 level playing field for participants, which can facilitate market access and reduce 

5 entry barriers for all—including new entrants.

6

7 Regulators benefit because interoperability T&C maximizes the benefits of 

8 new grid technology investments they approve through regulatory proceedings 

9 [134, 139].

10

11

12 6.1.2 Current practice

13

14 NIST worked with sector experts to create best practice guidelines for the development of 

15 T&C programs for smart grid systems and devices. The foundational products are the 

16 Interoperability Process Reference Manual (IPRM) standard [134] and accompanying User’s 

17 Guide [140]. The IPRM standard defines a process by which industry stakeholders may 

18 procure, test, and assert interoperability between disparate vendors of smart grid products 

19 built to specific standards. It includes practical guidance on requirements and 

20 recommendations for general test policies, test suite specifications, test profiles, 

21 interoperability T&C authority technical programs, governance, laboratory qualification, and 

22 process improvements. 

23

24 The IPRM standard defines an entity, the Interoperability Testing and Certification 

25 Authority, that serves as test program operator. Ideally, there should be an Authority to 

26 certify interoperability for each smart grid standard for which a T&C program is required.

27

28 Testing and Certification is an important aspect of the technology product development and 

29 deployment lifecycle. Unfortunately, T&C is often overlooked because of the added costs to 

30 equipment manufacturers for completing and maintaining product certification, the limited 

31 availability of appropriate test programs (see Section 6.4.3), and the lack of qualified testing 

32 organizations to perform the tests. These are among the main reasons for the persistent gap 

33 in the availability of testing programs for smart grid standards and interoperability.

34

35

36 6.2 Levels of Interoperability

37

38 There are many levels of interoperability, each with its own industry definitions. This is 

39 important for T&C because most standards, tests, and certifications have been created by 

40 industry to deliver a desired function and interoperability level.

41

42 One way to define the interoperability level is through the Open Systems Interconnection 

43 (OSI) 7-layer model [139]. This approach provides a method for defining interoperability 

44 within and across communications system levels. Another method for defining 

45 interoperability is the GridWise Architecture Council (GWAC) interoperability stack concept 

46 [141], which describes interoperability from a functional approach.
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1

2 Figure 22 – Levels of interoperability conceptual diagram

3

4 A practical way to characterize interoperability is though the integration concept. From plug5 and-play on one end of the spectrum to point-to-point integration on the other, each 

6 interoperability level describes the ease with which communication can be achieved across 

7 devices or systems, and the time and expense associated with overcoming any 

8 communications gaps. Figure 22 provides a cartoon representation of three interoperability 

9 levels, where plug-and-play allows for direct communication at little expense to the device 

10 operator and point-to-point integration requires development of custom interfaces that take 

11 considerable time and money to develop.

12

13 There are a few examples of plug-and-play interoperability in the electric grid. One example 

14 is the compatibility between electric vehicles and public charging stations. When the station 

15 and vehicle support the same plug type and charging protocol, charging begins as soon as the 

16 two are connected regardless of the fact that the vehicle and charging systems are owned by 

different actors.77 17

18

19 The middle interoperability level — where devices require integration efforts to work with 

20 the rest of the system — is more common. Substation equipment is a useful example due to 

21 the two dominant standards in this arena. A utility could have an existing substation 

22 designed around the DNP3 communications protocol [143] but wants to incorporate new 

23 piece of equipment with specific functionality supported by the GOOSE communications 

24 protocol [144]. This difference in designed-to communications protocols means the new 

77 Even with the plug-and-play interoperability that exists between electric vehicles and public charging stations [142], 

communications between the charging station and grid operators and markets remains highly constrained and 

interoperability is limited to the physical exchange of energy. 
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1 device will not be able to communicate with the rest of the substation without specific 

2 integration efforts. However, this integration issue can be addressed with the IEEE 1815.1-

3 2015 standard which provides a mapping between GOOSE and DNP3 that a gateway can use 

4 to translate between the two communication protocols [145]. A gateway conforming to IEEE 

5 1815.1-2015 would therefore allow the new device to interoperate with the rest of the 

6 substation.

7

8 Point-to-point integration is often referred to as a custom one-off solution. This type of 

9 integration is needed when integrating new equipment to existing systems that implement 

10 proprietary or obsolete communications protocols. This is a common problem in the electric 

11 grid due to the long service life of most grid equipment [48] and the need for older 

12 equipment to communicate with newer systems to enable new functionalities as part of grid 

13 modernization. This scenario will lead to a custom integration solution where the 

14 communication mapping between existing and new systems will need to start from scratch 

15 and cannot rely on a published standard. This type of integration is time-consuming and 

16 costly.

17

18

19 6.3 Types of Testing Processes

20

21 Developing testing and certification programs involves many processes, the steps for which 

22 are shown in Figure 23. Because the designed interoperability level for each product is a 

23 function of technical and business considerations, not every product or standard will 

24 complete all of the steps.

25

26

27 Figure 23 – Testing and certification development process

28
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1 6.3.1 Conformance and interoperability testing

2

3 Conformance testing ensures products conform to requirements detailed in a standard or 

4 other specification. Interoperability testing ensures that products from different vendors can 

5 communicate and exchange actionable information in the same system. Conformance testing 

6 does not guarantee interoperability because standards often include multiple options 

7 manufacturers can choose from to meet a requirement. Standards contain these 

8 implementation options to be flexible, but this optionality introduces significant product and 

9 systemwide variability that can inhibit interoperability.

10

11 Interoperability testing is more complex than conformance testing since manufacturers must 

12 agree to a common list of requirements to enable the products to work together. This is 

13 generally referred to as an implementation agreement and is an essential element of an 

14 interoperability test program. From these agreed upon requirements, an industry stakeholder 

15 group develops the protocol implementation conformance statement (PICS) for the test plan.

16

17 Implementing Agreements define a common interpretation of a standard 

18 which includes a specific subset of requirements from the original standard 

19 [140].

20

21 Protocol Implementation Conformance Statement (PICS) enables the 

22 development of a test plan from the requirements identified in the 

23 implementing agreement.

24

25 This process often leads to an implementation profile for a standard which serves as 

26 the basis for interoperability testing requirements. As discussed later in this chapter, 

27 the development of interoperability profiles may offer a way to identify a subset of 

28 requirements common to a specific implementation of a standard, thereby minimizing 

29 the differences between implementations of a standard for a common application.

30

31

32 6.3.2 Interoperability tests

33

34 An example of interoperability testing in the final step of Figure 23 above is a 

35 plugfest. An interoperability plugfest is an event where different vendors and 

36 stakeholders gather to conduct testing of a standard or specification. The goal of a 

37 plugfest is to determine if devices from different manufacturers are able to 

38 communicate and exchange information as specified in the requirements, and to show 

39 incompatibilities when interoperability is not achieved. A successful plugfest 

40 requires participation from equipment manufacturers, test support personnel, and 

41 witnesses.

42

43 Reports from recent plugfests, such as the 2017 IEC 61850 plugfest, indicate the 

44 value of these activities. The final report for this event identifies communication 

45 issues that occurred among devices due to their varied implementation of certain

46 aspects of the IEC 61850 standard. In one case a device had its network domain 
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1 address hardcoded and could not be dynamically changed to different values as 

2 required by tests. The device therefore failed the communication test [146].

3

4 Industry recognized the importance of plugfests in specifying product procurement 

5 requirements [147]. A purchaser can potentially require vendors to participate in 

6 plugfests to demonstrate the interoperability of their products. Plugfests also provide 

7 an avenue for vendors to showcase products and capabilities to potential customers, 

8 since utility staff can participate in the event as witnesses.

9

10 Interoperability testing is important because it can expose compatibility issues for 

11 devices from different vendors operating within a closed system. In this way, 

12 interoperability testing provides information manufacturers can use to refine their 

13 products, and also helps implementers avoid previously known integration issues. 

14

15 The key takeaway on conformance and interoperability testing is that they are both 

16 necessary to enable interoperability of smart grid devices and systems.

17

18

19 6.3.3 Certification regimes

20

21 Three certification types described in the IPRM standard are first party, second party, and 

22 third party. Table 6 provides a broad illustration of performance metrics related to the 

23 different certification types.

24

25 First-party certification is when a manufacturer attests that a product meets the 

26 standard’s requirements. This type of certification, often called self-certification, is 

common in industry.78 27 In first-party certification, the purchaser relies on the 

28 manufacturer developed test plan.

29

30 Second-party certification is when a user tests and certifies a product to verify that it 

31 meets the standard’s requirements. This type of certification relies on the user’s own 

32 test plan, which could include specific requirements based on their existing systems 

33 and is not scalable because it is difficult for other users to take advantage of this 

34 testing. In the smart grid it is often the utility that serves this role.

35

36 Third-party certification is done through an independent authority that includes a 

37 certification body and associated test lab. Third-party certification has public test 

38 plans, which facilitate transparent audit and evaluation of the testing implementations. 

39 Third-party certification by fully vetted and independent testing authorities is one of 

40 the best means to deliver interoperability.

78 An example of first party certification is the ANSI C12 family of standards for electric meters [148]. The meters are 

mostly procured with the manufacturer’s certification of conformance to the C12 standard. 
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1 Table 6 – Certification regime characteristics (illustrative)

Speed Transparency Independence

First Party High Low Low

Second Party Medium Medium Medium

Third Party Low High High

2

3

4 6.4 Current Smart Grid Testing Initiatives

5

6 NIST is involved in a number of initiatives designed to support development of testing and 

7 certification regimes across the sector, a few of which are described below.

8

9 6.4.1 Testing support

10

11 Testing events and test program formulations are important catalysts for building a robust 

12 testing ecosystem. However, these activities are often done by volunteers with limited 

13 support from organizers. More support is needed to drive these activities to success and 

14 further develop the smart grid testing and certification ecosystem beyond the current nascent 

15 stage. NIST works with the community in developing test protocols for conformance 

assessment,79 and also participates in testing activities such as plugfests.80 16

17

18 6.4.2 Catalog of standards

19

20 Each prior version of this Framework included a listing of smart grid-relevant standards, 

21 requirements, and guidelines identified through a consensus-driven stakeholder engagement 

22 process. In the 2010 Framework [33], context for the enumerated standards was provided 

23 through discussion of relevant applications and needed improvements. By the 2014 

24 Framework [19], the contextual information grew to include capability descriptions and 

25 mappings to the Smart Grid Conceptual Model domains and other standards catalogs. At the 

26 same time, in just four years the number of standards included in the listing grew from 25 to 

27 72.

28

29 Expansion of the standards landscape has continued apace since the 2014 Framework [60]. 

30 This fact, along with the growing range and amount of contextual information provided for 

31 each entry, would have limited the usefulness and usability of periodically published static 

lists of smart grid standards. NIST has therefore worked with industry81 32 to develop the 

33 SEPA Catalog of Standards (COS) [151], an online version of the smart grid-relevant 

34 standards lists published in prior Frameworks. The COS is publicly accessible, allows for 

35 navigation using NIST Smart Grid Conceptual Model domains and other parameters, and is 

36 updated regularly through a consensus-based and transparent process. 

79 For example, NIST staff is working on a test suite specification (TSS) for the utility power profile for precision timing 

protocol (IEEE C37.238 and IEC 61850-9-3), which will serve as the basis for the testing program the IEEE Conformity 

Assessment Program (ICAP) will operate [149]. 80 NIST staff have developed test harnesses for, and participated in, interoperability plugfests such as the UCAIug hosted 

2017 IEC 61850 Interoperability Plugfest [150]. 81 Through the Smart Electric Power Alliance’s Testing and Certification Working Group
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1 6.4.3 Catalog of test programs

2

3 The COS provides curated and useful information on standards relevant to smart grid 

4 development and deployment [151]. The COS does not, however, include information on 

5 associated test programs for these standards. A lack of readily accessible information on the

6 availability of T&C programs is a barrier to further adoption and limits the interoperability 

7 benefits to industry that these techniques could provide.

8

9 To address this information gap, NIST conducted a landscape analysis on the availability of 

10 T&C programs for smart grid standards [60] and determined that T&C programs are 

11 available for only a small percentage of interoperability standards (see Figure 24). The 

12 analysis also revealed there is a significant challenge in finding test programs even for those 

13 with expert industry knowledge and awareness, and that industry would benefit from a 

14 repository that contains information on available test programs. 

15

In response to its findings, NIST is working with industry81 16 to create a Catalog of Test 

17 Programs [152]. There are several industry test programs that are beneficial to 

18 interoperability of smart grid systems and devices, and a comprehensive directory of 

19 available test programs will provide value to the stakeholder community. Such a catalog 

20 provides guidance to equipment purchasers on whether reference test programs are available, 

21 and also provide visibility for test program operators — potentially increasing their usage. 

22

23 Built from the information generated during the NIST landscape analysis, the Catalog 

24 provides a directory of industry test programs that support assessments against 

25 interoperability standards. It is a one-stop, publicly accessible resource to support utilities 

26 and vendors as they seek to identify available device testing resources. This initiative will 

27 regularly update the Catalog, and is expected to foster collaborations between test programs 

28 and labs thereby expanding coordination across the T&C ecosystem.

29

30 The complete list of interoperability standards evaluated for NIST’s T&C landscape analysis 

31 is found in Appendix J – List of Reviewed Smart Grid Interoperability Standards [60].
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1

2 Figure 24 – Interoperability standards and associated testing and certification

3

4 6.4.4 Reference interoperability procurement language

5

6 Procurement language is crucial to specifying product interoperability requirements so that 

7 integration issues can be addressed and mitigated before deployment. It is more efficient for 

8 customers to develop interoperability requirements at the purchasing stage than it is to deal 

9 with integration issues after products are delivered. Failure to reference specific 

10 interoperability requirements in the procurement language increases the chances that the 

11 resulting product will not be interoperable with other equipment or systems.

63

19

113

39

30

14

0

20

40

60

80

100

120

Standards T&C Programs Standards T&C Programs Standards T&C Programs

Information Model Communications Protocol Performance

Number of Standards Evaluated

 

Standards Independent T&C 1st Party T&C Planned T&C

Communication

Protocol

Physical 

Performance

Communication 

Protocol

+ 

Physical 

Performance

Information Model

+

Communication Protocol 

+ 

Physical Performance

Communication 

Protocol

+ 

Information

Model

Information

Model

Total 240 SG standards 

Reviewed
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1 A challenge in this space is that technical requirements for acquisitions by utilities and other 

2 customers are often focused on the functional specifications of the systems to be purchased, 

3 and do not include appropriate descriptions for the interoperability requirements. One 

4 solution is to develop reference language so that it is readily available to specify 

5 interoperability requirements during procurement. 

6

7 NIST is partnering with SEPA and the DOE’s Grid Modernization Laboratory Consortium 

8 (GMLC) to develop suggested guidelines for interoperability procurement language. This 

9 effort will develop a list of interoperability criteria and associated metrics that can be applied 

10 to stakeholder procurement language.

11

12

13 6.5 Towards Interoperability Profiles

14

15 As described previously, the latest landscape assessment reveals the availability of T&C 

16 programs for smart grid standards is quite limited (see Section 6.4.3). One opportunity to 

17 accelerate T&C program development is through the creation of interoperability profiles, 

18 wherein application-derived interoperability requirements are specified. Another is through 

19 the development of open source test tools. Both approaches can provide stakeholders a 

20 greater sense of trust regarding device capability and performance.

21

22 6.5.1 Interoperability profiles

23

24 Interoperability Profiles reduce implementation and testing complexity by curtailing and 

25 clarifying the range of interoperability requirements to a well-defined subset of those 

26 available through standards. Once agreed upon by a user community, testing authority, or 

27 standards body, the Interoperability Profile would describe a subset of supported data types, 

28 logical nodes and elements, or services, and that subset would narrow interoperability gaps 

29 by reducing the available degrees of freedom for implementing standards by the device 

30 supplier, implementer, and system owner. 

31

32 Interoperability Profiles would not replace or be considered standards, but instead would 

33 clarify standards-based interoperability implementation requirements for all stakeholders. 

34 Interoperability Profiles could therefore take many different forms based on the technology 

35 and underlying standards, and by defining the elements of the standard to be utilized for 

36 specific application environments would give all stakeholders greater confidence in asset 

37 functionality.

38

39 The basic set of elements for an Interoperability Profile include the asset description and 

40 associated physical performance specifications, communication protocol, and information 

41 model. The growing complexity of information models means that only a subset is likely to 

42 be necessary for any single application or piece of equipment. This can lead to 

43 interoperability failures when devices compliant to the same standard attempt to 

44 communicate different parts of the same data model. This communications failure could be 

45 mitigated through the application of Interoperability Profiles that define implementations 

46 using a specific subset of the broader standard.
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1 An Interoperability Profile with a narrow set of implementation requirements could be more 

2 easily tested for certification, and eventually could be listed by vendors that support it or 

3 could be used in procurement specifications by end users. This could facilitate the 

4 development and utilization of T&C programs and advance interoperability for smart grid 

5 equipment and systems.

6

7

8 6.5.2 Example of an interoperability profile

9

10 The core elements of the Interoperability Profile approach have already been successfully 

11 demonstrated for smart inverters. California Rule 21 [153] and IEEE 1547-2018 [154] both 

12 define the specifications for interconnection and interoperability of distributed energy 

13 resources with associated electric power system interfaces. The standards include physical 

14 performance specifications, communication protocols, and require data elements. While the 

15 physical performance specifications are similarly prescriptive, Rule 21 and IEEE 1547 

16 employ different approaches to the requirements for communication protocols and data 

17 elements.

18

19

20 Figure 25 – Potential implementation combinations for IEEE 1547-2018

21 An inverter communicating via any one of three communications protocols (IEEE P2030.5, 

IEEE 1815, or Modbus) can conform to the IEEE 1547 standard.82 22 The standard also defines 

82 According to the IEEE 1547-2018 standard, a DER will conform to the standard if it supports any one of three 

communications protocols, including: IEEE 2030.5 (Smart Energy Profile 2.0), IEEE 1815 (Distributed Network Protocol 

v3), and SunSpec Modbus. It is therefore possible for two DERs which conform to the IEEE 1547-2018 standard to be 

unable to communicate with each other because they support different communication protocols.

SEP 2.0

DNP3

Building 

Automation Thermostat

CIM

Microgrid 

Controller Inverter Smart Meter EV Charger Substation Automation

61850

MQTT

MODBUS

XMPP

ANSI C12.22

61850

SEP 2.0

FSGIM

ANSI C12.19

MODBUS

 IP2

 IP3

 IP4

 IP5

 IP6

 IP7

 IP8

 IP9

 IP10

 IP11

 IP12

BACNet DNP3

OpenADR

 IP1

Hardware / Performance Requirements

Communication Protocols
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1 required data elements but does not specify a particular information model, and section 10 of 

2 IEEE 1547 describes additional communications protocols and data models (including IEC 

3 61850) that could also be used. The standard therefore offers numerous permutations of 

possible interoperability implementations, as shown in Figure 25.

83 4 While the inverter 

5 physical performance requirements are clear, the relatively large number of potential 

6 communications protocols and data model implementations could limit the ability to test for 

7 and certify device interoperability under the IEEE 1547 standard.

8

9 California Rule 21 also establishes rules for interconnection of inverter-based DER to the 

10 grid. While the physical specifications mirror those of IEEE 1547, Rule 21 specified IEEE

11 P2030.5 as the required communication protocol and IEC 61850 as the required information 

12 model. The resulting combination is shown in Figure 26. This example demonstrates the 

13 application of an Interoperability Profile on existing standards by narrowing the degrees of 

14 freedom and complexity for implementing the required communication.

15

16

17 Figure 26 – California Rule 21 interoperability profile implementation

18

19 Rule 21 clarified inverter interoperability requirements, and an independent testing and 

20 certification program has been formed [155] that has since been adopted as a requirement by 

21 utilities and system operators in other regions of the country [156].

83 The communications protocol and information model labels “SEP 2.0” and “DNP3” in Figure 26 refer to the protocols 

and models defined in standards IEEE P2030.5 and IEEE 1815, respectively.

SEP 2.0

DNP3

Building 

Automation Thermostat

CIM

Microgrid 

Controller Inverter Smart Meter EV Charger Substation Automation

61850

MQTT

MODBUS

XMPP

ANSI C12.22

61850

SEP 2.0

FSGIM

ANSI C12.19

MODBUS

 IP2

BACNet DNP3

OpenADR

Hardware / Performance Requirements

Communication Protocols
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1 6.5.3 Interoperability profiles work plan

2

3 Originally described during a 2018 workshop [23], NIST has collaborated with industry and 

4 other stakeholders to refine the Interoperability Profile concept and content. The process for 

5 developing an Interoperability Profile includes selecting system interfaces and developing a 

6 use case to define functional requirements, and then creating a series of documents that 

7 describe specific interface requirements and provide implementation guidance.

8

9 Developing an Interoperability Profile first requires identifying an appropriate device or 

10 system interface. Interface selection will make or break the entire Profile and must present a 

11 clear and large enough value proposition to stimulate industry participation in the longer12 term Interoperability Profile development process. Evaluation criteria for assessing the value 

13 of any single interface include: industry interest, technological maturity and field 

14 deployments of the interface, and the existence of an ecosystem or other organization that 

15 can drive Interoperability Profile adoption. Interfaces that facilitate exchanges across smart 

16 grid Conceptual Model domains (see Appendix A – Smart Grid Conceptual Model Domains) 

17 are particularly appropriate.

18

19 Following interface selection, a use case is developed to capture stakeholder requirements, 

20 describe the desired interface functions, provide a list of applicable standards, and identify 

21 relevant system actors. With an approach drawn from IEC methods [157], the use case 

22 provides an overview of the Interoperability Profile to be developed and is the guiding 

23 document for determining specific Profile requirements.

24

25 An application guide is created next, wherein the requirements set forth in the Profile use 

26 case are mapped to existing standards. This process of identifying relevant standards 

27 clarifies the basic structure for how the specific Interoperability Profile requirements will be 

28 met.

29

30 The Interoperability Profile is developed next, wherein the mapping in the application guide 

31 is used to specify standards-based implementation options to satisfy the original use case 

32 requirements. The Interoperability Profile will describe how to achieve the interoperability 

33 and functionality requirements of the use case by specifying the appropriate configuration 

34 options from each standard described in the application guide.

35

36

37 6.5.4 Open source test tool development

38

39 A key component of the T&C process is the test harness, which is created by translated test 

40 cases into automated scripts that can be executed to evaluate interoperability functions. Test 

41 harnesses create efficiency by automating the test process, but creating test harnesses is often 

42 the costliest part of the test program and requires a different skillset than traditional standards 

43 development. This high development cost translates to high fees for using test harnesses, and 

44 industry has stated the overall cost for developing and using test harnesses is a significant 

45 barrier to entry for T&C programs [23].
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1 Once a complete Interoperability Profile is available, the smart grid community can then 

2 assess the viability of developing the relevant test harness in an open source environment. 

3 Similar to open source software development, the community would be expected to develop 

4 and manage the tool. The benefit of this approach is that it would allow for broad 

5 participation in the test harness development process, and thereby reduce entry barriers for 

6 T&C activities.

7

8 Upon completion of open source test tools, equipment manufacturers, customers, or 

9 independent test program operators could all have access to and benefit from the capability. 

10 This access to the test tool is, in turn, expected to accelerate innovation based upon the 

11 Interoperability Profile specifications.

12

13

14 6.6 Conclusions and Future Work

15

16 Meaningful interoperability across the power sector is difficult to achieve and — at this time 

17 — virtually impossible to ensure. Testing and certification programs are key to enhancing 

18 interoperability but are limited in availability and scope. Test programs must also evolve 

19 beyond their current practice focusing on standards-driven conformance assessment into a 

20 model that supports the types of tests which would better guarantee interoperability of device 

21 and system. Interoperability Profiles and open source test harnesses are two tools that, if 

22 properly developed, would facilitate expansion of interoperability focused T&C programs. 

23

24 Interoperability Profiles can constrain the wide-ranging implementation optionality inherent 

25 to most standards, and instead describe application-specific subsets of standard requirements 

26 that would reduce the degrees of freedom available to product designers and service 

27 implementors. Rather than constraining innovation, this reduced implementation subset 

28 would allow the community to purposefully combine selected parts of one or more standards 

29 that best support their selected application upon which innovation could flourish. A 

30 narrowed subset of implementation requirements should also enable the development of 

31 testing and certification regimes that would better assure interoperability capabilities.

32

33 The electric vehicle interface has been identified as one that would benefit from improved 

34 interoperability [54], and development of an initial Interoperability Profile for managed 

35 charging is underway. Creation of the first Interoperability Profile will further socialize the 

36 concept and provide an opportunity to refine the development process. There will need to be 

37 more Interoperability Profiles in the future, with several additional candidate interfaces 

38 already identified [54]. 

39

40 After creation of Interoperability Profiles, the development of open source test harnesses 

41 would eliminate barriers to entry for interoperability testing efforts, and facilitate a rapid 

42 expansion of interoperability focused formalized T&C programs.
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1 Conclusion

2

3 Interoperability remains a critical yet underdeveloped capability of the power system. 

4 Significant grid modernization has occurred in the years since the 2007 Energy Independence 

5 and Security Act was signed into law, but the proliferation of technology and associated 

6 standards complicated the interoperability landscape. The expanding use of distributed 

7 energy resources and other technologies has further expanded the interoperability challenge.

8

9 This revision of the NIST Smart Grid Interoperability Framework uses evolving technology 

10 and power system architectures as context for describing a new set of interoperability 

11 perspectives. Examined through emerging operational, economic, and cybersecurity 

12 challenges and opportunities, distributed and customer-sited resources figure prominently in 

13 the future smart grid—as do distribution systems and other key integrators.

14

15 Because interoperability requires shared requirements to enable information exchange 

16 between disparate systems, expanding the available communications toolset to facilitate 

17 common understanding across stakeholders is a priority of this Framework. Models that aid 

18 our understanding of interoperability and other smart grid concerns have been updated or 

19 newly introduced in the early sections of this Framework. 

20

21 The NIST Smart Grid Conceptual Model is updated to reflect technology and platform22 driven emerging capabilities in the Customer and Distribution Domains as well as the 

23 structural reorganization of a system more reliant on shared infrastructures and distributed 

24 resources. A series of Communication Pathways Scenarios help readers examine how 

25 interface requirements might change with different system architectures or control strategies. 

26 And an ontology for the smart grid is introduced that provides reference language which can 

27 be used to clarify communication between stakeholders.

28

29 The relationship between emerging physical interactions and grid operations becomes more 

30 important with the ongoing transition from analog to digital energy technologies. The 

31 emerging system dynamics provide critical context to the informational focus of prior 

32 Frameworks. Physical interoperability and trustworthiness are therefore established as 

33 critical complements to conventional (informational) interoperability concepts. 

34

35 Interoperability is identified as a principal enabler of new system control schemes necessary 

36 to manage the active participation of distributed resources in a system undergoing the 

37 devolution of control authority, all while empowering customers to provide solutions across 

38 numerous scales. This expands the interoperability concept beyond the traditional utility39 centric focus of interoperability as a mechanism to decrease system integration costs.

40

41 More than just a mechanism for measurement and control signals, interoperability is key to 

42 the economics of the future grid. The traditional means of ratemaking and cost recovery are 

43 under strain as growth in distributed energy resources and changing customer capabilities 

44 alter traditional economic dependencies and the role of the distribution utility. 
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1 As value propositions change throughout the grid interoperability can minimize transaction 

2 costs and minimize entry barriers to market participation, thereby facilitating the creation of 

3 new participatory and economic opportunities across the system. Interoperability is also key 

4 to ensuring the technical and economic benefits from grid modernization flow across smart 

5 grid Domains and stakeholder interests as the electricity system evolves, rather than accruing 

6 to single firms or stakeholder classes.

7

8 The value brought through introduction of ever-growing technologies and resources also 

9 carries with it a growing cybersecurity risk. Utilities and other organizations wanting to 

10 benefit from emerging interoperability-enabled opportunities will not be able to assure 

11 security by limiting connectivity through physical isolation or other overly restrictive access 

12 regimes. Instead, utilities and other stakeholder organizations will have to consider in 

13 concert the desired outcomes for the grid and the interfaces (and informational exchanges) 

14 that must be protected. The former lends itself to examination through institutional 

15 capabilities and processes, which if implemented properly will position a utility or other 

16 organization to achieve the latter. 

17

18 This Interoperability Framework presents a Cybersecurity Risk Profile for the smart grid as a 

19 first step towards assessing organizational risk and establishing cybersecurity priorities. An 

20 updated assessment of logical interface categories in a High-DER scenario is also presented 

21 as a mechanism to improve our understanding of the cybersecurity requirements associated 

22 with new technology interfaces and provide a mapping to an existing set of category-driven 

23 guidelines.

24

25 Through all of this, testing and certification emerges as a critical enabler of grid 

26 modernization. The benefits to industry range from operational trustworthiness to investor 

27 confidence. But the optionality inherent to standards requirements generally allows for non28 interoperability even among proper implementations. Therefore, the current industry focus 

29 on certifying conformance to individual standards is only the first step toward assuring 

30 interoperability of devices or systems.

31

32 The concept of an Interoperability Profile is proposed as one solution to the interoperability 

33 challenge. Built upon concepts of both physical and informational interoperability, an 

34 Interoperability Profile describes the communications protocol and data model requirements 

35 necessary to achieve a specific set of physical functions. Based on existing standards, these 

36 Profiles describe the subsets of requirements that, when implemented and verified through 

37 testing and certification, would ensure interoperability across devices and systems.

38

39 Much work must still be done to realize the smart grid interoperability promise. Case studies 

40 and practical guidelines that translate the abstractions of frameworks and other high-level

41 interoperability requirements into actionable lessons will help stakeholders break through the 

42 sometimes-paralyzing uncertainty of highly complex systems and allow them to identify and 

43 act on strategies to advance smart grid capabilities.

44

45 Interoperability is more important today than ever before. Future grid operations, economics, 

46 and cybersecurity will demand vast interoperability improvements, and the customer will 
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1 depend on interoperability to achieve their objectives and obtain value from their investments 

2 no matter their specific priorities. The concepts laid out in this Framework provide a 

3 foundation from which the smart grid community and NIST can advance grid modernization 

4 and realize the full set of interoperability benefits and opportunities.
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1 Appendix A – Smart Grid Conceptual Model Domains

2

3 A.1 - Customer Domain

4

5 The customer is ultimately the stakeholder that the entire grid was created to support. This is 

6 the domain where electricity is consumed, but is increasingly a domain where electricity is 

7 actively managed and generated as well (see Figure 27). Actors in the Customer domain 

8 enable customers to manage their energy usage and generation. Some actors also provide 

9 control and information flow between the Customer domain and the other domains. The 

10 boundaries of the Customer domain are typically considered to be the utility meter and the 

11 energy services interface (ESI). The ESI provides a secure interface for utility- or service 

12 provider-to-customer interactions. The ESI in turn can act as a bridge to facility-based 

13 systems, such as a building automation system (BAS) or a customer’s premise management 

14 system.

15

16

17

18

19 Figure 27 – Overview of the Customer domain

Distribution

Thermal 

Storage

Customer

Operations

Markets

Building / 

Commercial

Home

Industrial

Distributed 

Wind

Co-Generation

Lighting

Sub-Metered 

Processes

Meter

Industrial 

Gateway

Appliances

Automation

Thermostat

Home 

Gateway 

(ESI)

Meter

Solar 

Generation

MultiDwelling

Meter

Building 

Gateway

Electric 

Vehicle

Campus

Solar

Building 

Automation

Automation

Source: DRAFT NIST Smart Grid Framework 4.0

Generation including DER

Service 

Provider

Internal Communication Flows

Electrical Flows

Domain

External Communication Flows
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1 The Customer domain is usually segmented into sub-domains for home, 

2 building/commercial, and industrial. The energy needs of these sub-domains are typically 

less than 20kW of demand for a residence,84,85 3 20-200 kW for commercial buildings, and 

4 over 200kW for industrial. Each sub-domain has multiple actors and applications, which may 

5 also be present in the other sub-domains. 

6

7 Each sub-domain has a meter actor and includes an energy services interface (ESI), which is 

8 the primary service interface to the Customer domain. The ESI may reside at an end-device, 

9 in a premise-management system, in the meter, or outside the premises, and may 

10 communicate with other domains via the advanced metering infrastructure (AMI) or other

11 means, such as the internet. The ESI provides the interface to devices and systems within the 

12 customer premises, either directly or via a home area network (HAN), other local area 

13 network (LAN), or some other mechanism in the future.

14

15 There may be more than one communications path per customer. Entry points may support 

16 applications such as remote load control, monitoring and control of distributed generation, in17 home display of customer usage, reading of non-energy meters, and integration with building 

18 management systems and the enterprise. They may provide auditing/logging for 

19 cybersecurity purposes. 

20

21 In this revision, the Customer domain is electrically connected to the Distribution and 

22 Generation Including DER domains. This reflects the potential to connect, in a behind the 

23 meter fashion, up to the service rating of DER (up to 320A, nominally for single-phase 

24 services), as well as the potential for community energy storage and other DER connected to 

25 the distribution system. This diversity in scale and siting highlights a challenge in slotting 

26 DER into a specific role within the Conceptual Model, as DERs satisfy different needs 

27 depending upon the point of connection.

28

29 This Customer domain communicates with the Generation including DER, Distribution, 

30 Operations, Market, and Service Provider domains. Examples of typical application 

31 categories in the Customer domain are in Table 7.

84 Most residences have either 100A or 200A service, or 24kVA and 48kVA maximum, respectively, at 240VAC. A single 

EV can introduce loads up to 2.4kVA (Level 1) or 19.2kVA (Level 2) when running at maximum output.

85 Peak demand for large multi-family dwellings can exceed 1MW, although the per-residence energy consumption can be 

60% less than that of single family homes [158]. 
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1 Table 7 – Typical application categories in the Customer domain

Example 

Application 

Category

Description

Building or Home 

Automation

A system that is capable of controlling various functions within a

building, such as lighting, temperature control and appliance 

usage.

Industrial 

Automation

A system that controls industrial processes such as manufacturing

or warehousing. These systems have very different requirements

compared to home and building systems.

Micro-generation

Includes all types of distributed generation including: solar, wind,

and hydroelectric generators. This generation harnesses energy for

electricity at a customer location. May be monitored, dispatched, 

or controlled via communications.

Storage

Means to store energy that may be converted directly or through a

process to electricity. Examples include thermal storage units, and

batteries (both stationary and electric vehicles)

2
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1 A.2 - Markets Domain

2

Markets are where grid assets and services are bought and sold.86 3 Some markets yet to be 

4 created may be instrumental in defining the smart grid of the future, particularly with DER 

and aggregated DER.87 5 Entities in the Markets domain exchange price information and 

6 balance supply and demand within the power system (see Figure 28). The boundaries of the 

7 Markets domain include the edge of the Operations domain where control happens, the 

8 domains supplying assets (Generation including DER, Transmission, and Distribution), the 

9 Service Provider domain, and the Customer domain. In short, the Markets domain interfaces 

10 with all domains of the smart grid.

11

12 Communication flows between the Markets domain and the domains supplying energy are 

13 critical because efficient matching of production with consumption is dependent on markets 

14 or their proxies. Energy supply domains include the Generation Including DER—and more 

15 recently the Customer—domains. The North American Electric Reliability Corporation 

16 (NERC) Critical Infrastructure Protections (CIP) standards consider suppliers of more than 

17 300 megawatts to be bulk generation; most DER is smaller and is typically served through 

18 aggregators. 

19

20 Figure 28 – Overview of the Markets domain

86 Entities within the electric power sector have engaged in markets for inputs such as equipment, labor, and fuel since the 

outset of the sector’s development. 87 Some utilities utilize market concepts to determine the avoided operational and infrastructure costs associated with 

deploying DER on their grid.
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1 DERs have an active and growing role in several wholesale markets through aggregation, and 

2 will participate to a greater extent as the smart grid becomes more interactive. Hyper-local 

3 markets based on peer-to-peer principles such as Transactive Energy have been demonstrated 

4 to work for a variety of applications and services, and appear poised to significantly expand 

5 the design and role of market interactions with the Customer domain. This is in addition to 

6 the active and growing role that DER, via aggregation, will have in wholesale markets.

7

8 This revision of the Markets domain introduces the “Platform” icon to represent emerging 

9 opportunities for interactions among nontraditional grid actors to create value. 

10 Fundamentally markets are formed of sets of actors, which collectively establish the price of 

11 goods and services [159]. Advances in information and communication technologies have 

12 reduced the costs of coordinating and facilitating many types of trades, uncovering new 

13 economic opportunity as falling transaction costs improve the value propositions offered by 

14 entities at the edge of the grid. Organizational structures such as platforms are increasingly 

15 pivotal to the erosion of transaction costs and the formation of decentralized markets for 

16 services. The economic potential for the emergence of distribution level platforms is 

17 growing with the number and diversity of organizations attempting to pursue opportunities 

18 on the electric grid [28].

19

20 A major uncertainty remains the relationship between wholesale markets and distribution 

21 markets, including the information flows between market operators and participants at each 

22 level. The economic fundamentals and legal structures governing market activities and price 

23 levels in each market segment (retail and wholesale) co-evolve over time. That is, prices in 

24 distribution level markets influence wholesale prices, and vice versa.

25

26 Conventionally, prices are determined by rate designs and tariffs adopted by the applicable 

27 regulatory authority. These rates include flat rate, time of use rates, or other more dynamic 

28 rate designs, such as real time pricing. Rates are primarily a means by which the utility 

29 recovers its authorized revenue requirement. Furthermore, rates can also provide a signal to 

30 customers on when it is more or less costly to consume electricity thereby encouraging 

31 customers to shift consumption to other hours. Emerging technologies that can dynamically 

32 and autonomously interpret customer preferences while responding to signals of price, 

33 resource availability, and service provision will enable customers to adopt more active 

34 strategies for engaging with the electric grid.

35

36 Communications for Markets domain interactions must be reliable, traceable, and auditable. 

37 Also, these communications must support e-commerce standards for integrity and 

38 nonrepudiation. As the percentage of energy supplied by small DER increases, requirements 

39 for the allowed latency in communications with these resources will have to be formally 

40 established.

41

42 The high-priority challenges in the Markets domain are: extending price and DER signals to 

43 each of the Customer sub-domains; simplifying market rules; expanding the capabilities of 

44 aggregators; ensuring interoperability across all providers and consumers of market 

45 information; managing the growth (and regulation) of retailing and wholesaling of energy; 

46 providing access to actionable data about the customer and the grid to support these new 
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1 technologies and resources; and evolving communication mechanisms for prices and energy 

2 characteristics between and throughout the Markets and Customer domains.

3

4 Table 8 – Typical applications in the Markets domain

Example 

Application Description

Market 

Management

Market managers include ISOs for wholesale markets or New York 

Mercantile Exchange (NYMEX)/Chicago Mercantile Exchange 

(CME) for forward markets in many ISO/RTO regions. Markets can 

be used to identify transmission, resource, capacity, and other service 

needs. These markets may also treat non-traditional resources, like 

storage and demand response, similar to traditional dispatchable 

generation.

Retailing

Retailers sell power to end-customers and may in the future aggregate 

or broker DER between customers or into the market. Most are 

connected to a trading organization to allow participation in the 

wholesale market.

DER 

Aggregation

Aggregators combine smaller participants (as providers, customers, or 

curtailment) to enable distributed resources to participate in the larger 

markets.

Trading

Traders are participants in markets, which include aggregators for 

provision, consumption, curtailment, and other qualified entities. 

There are a number of companies whose primary business is the 

buying and selling of energy.

Market 

Operations

Market operations make a particular market function smoothly. 

Functions include financial and goods-sold clearing, price quotation 

streams, audit, balancing, and more.

Ancillary 

Operations

Ancillary operations provide a market to provide frequency support, 

voltage support, spinning reserve, and other ancillary services as 

defined by FERC, NERC, and the various ISOs. These markets 

normally function on a regional or ISO basis, although local 

implementations may become more prevalent as new capabilities 

continue to be introduced to the Distribution and Customer domains. 

Platform

A governance structure or mechanism for connecting potentially 

diverse organizations and actors that seek to create and deliver value 

through interaction (including interoperation).

5
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1 A.3 - Service Provider Domain

2

3 Actors in the Service Provider domain perform services to support the business processes of

4 power system producers, distributors, and customers (see Figure 29). These business 

5 processes range from traditional utility services, such as billing and customer account 

6 management, to enhanced customer services, such as management of energy use and home 

7 energy generation.

8

9

10 Figure 29 – Overview of the Service Provider domain

11

12 Service providers create new and innovative services and products to meet the requirements 

13 and opportunities presented by the evolving smart grid. Services may be performed by the 

14 electric service provider, by existing third parties, or by new participants drawn by new 

15 business models. Emerging services represent an area of significant new economic growth.

16

17 The priority challenge in the Service Provider domain is to develop key interfaces and 

18 standards that will enable a dynamic market-driven ecosystem while protecting the critical 

19 power infrastructure. These interfaces must be able to operate over a variety of networking 

20 technologies while maintaining consistent messaging semantics. The service provider must 

21 not compromise the cybersecurity, reliability, stability, integrity, or safety of the electrical 

22 power network when delivering existing or emerging services. 
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1 The Service Provider domain is updated here to include an explicit focus on system-level 

2 issues that keep the electrical grid running. Where earlier versions of the Service Provider

domain focused on managing specific assets and functions for their customers,88 3 this revision 

4 reflects the expanding focus of third-party and other service providers towards co-optimizing 

energy and infrastructure requirements across multiple customers and value streams.89 5 The 

6 introduction of an energy management icon and communications flows with additional 

7 domains reflects the expanding service provider roles.

8

9 The Service Provider domain shares interfaces with the Generation including DER, 

10 Distribution, Markets, Operations, and Customer domains. Communications with the 

11 Operations domain are critical for system control and situational awareness; communications 

12 with the Markets and Customer domains are critical for enabling economic growth through 

13 the development of “smart” services. For example, the Service Provider domain may provide 

14 the interface enabling the customer to interact with the market.

15

16 The addition of communications to the Distribution and Generation including DER domains 

17 reflects the importance of higher DER penetration into utility portfolios, a condition that is 

18 likely under all regulatory and market structures given the scalability and rapidly declining 

19 costs of many distributed energy technologies [162]. Regardless of whether these new 

20 communication flows are from connecting directly to a single, large DER or to an 

21 aggregation of DERs behind an interface in the Distribution or Customer domains, these 

22 connections represent new challenges for system actors. 

23

24 Some benefits to the service provider domain from the deployment of the smart grid include:

25

26 • The development of a growing market for non-utility providers to configure value27 added services and products to customers, utilities, and other stakeholders at 

28 competitive costs;

29 • The decrease in cost of business services for other smart grid domains;

30 • A decrease in power consumption and an increase in power generation as customers 

31 become active participants in the power supply chain; and

32 • Better aligning consumption with service conditions, such as price or scarcity, and 

33 shifting consumption to optimize the operation of the electric grid.

88 For example, managing a building or facility for a commercial or residential customer, or certain functions such as 

customer account management for utility customers.

89 As value and benefits for third-party-managed DERs like storage are stacked, the focus and interactions of service 

providers will naturally expand beyond traditional single-customer relationships [160]. Furthermore, as third-party service 

providers assume larger roles in retail energy services, the provider’s responsibility to manage impacts on grid infrastructure 

will grow [161].
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1 Table 9 – Typical applications in the Service Provider domain

Example 

Application Description

Customer 

Management

Managing customer relationships by providing point-of-contact and 

resolution for customer issues and problems.

Installation & 

Maintenance

Installing and maintaining premises equipment that interacts with the 

smart grid.

Building 

Management

Monitoring and controlling building energy and responding to smart 

grid signals while minimizing impact on building occupants.

Home 

Management

Monitoring and controlling home energy and responding to smart grid 

signals while minimizing impact on home occupants.

Energy 

Management

Managing assets—often sited at multiple locations—to co-optimize for 

requirements and objectives at multiple scales and for multiple 

customers.

Billing Managing customer billing information, including providing billing 

statements and payment processing.

Account 

Management Managing the supplier and customer business accounts.

2
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1 A.4 - Operations Domain

2

3 Actors in the Operations domain are responsible for the smooth operation of the power 

4 system. Today, the majority of these functions are the responsibility of a regulated utility 

5 (Figure 30).

6

7 The smart grid will enable more of these functions to be provided by service providers. No

8 matter how the Service Provider and Markets domains evolve, there will still be functions

9 needed for planning and operating the service delivery points of a regulated utility that owns 

10 and manages the electrical conductors, or wires, that make up the distribution system.

11

12

13 Figure 30 – Overview of the Operations Domain

14

15 Currently, at the physical level, various energy management systems are used to analyze and 

16 operate the power system reliably and efficiently. The Operations domain is updated here to 

17 include communication flows with the Generation Including DER domain to highlight the 

18 importance of resource awareness—including for DERs—in state awareness.
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1 Representative applications within the Operations domain are described in (Table 10). 

2 These applications are derived from the International Electrochemical Commission (IEC) 

3 61968-1 Interface Reference Model (IRM) for this domain.

4

5 Table 10 – Typical applications in the Operations domain

Example 

Application Description

Monitoring

Network operation monitoring roles supervise network topology, 

connectivity, and loading conditions, including breaker and switch 

states, as well as control equipment status and field crew location and 

status.

Control

Network control is coordinated by actors in this domain. They may 

only supervise wide area, substation, and local automatic or manual 

control.

Fault 

Management

Fault management roles enhance the speed at which faults can be 

located, identified, and sectionalized, and the speed at which service 

can be restored. They provide information for customers, coordinate 

workforce dispatch, and compile information statistics.

Analysis

Operation feedback analysis roles compare records taken from realtime operation related with information on network incidents, 

connectivity, and loading to optimize periodic maintenance.

Reporting and 

Statistics

Operational statistics and reporting roles archive online data and 

perform feedback analysis about system efficiency and reliability.

Network 

Calculations

Real-time network calculations (roles not shown) provide system 

operators with the ability to assess the reliability and security of the 

power system.

Training Dispatcher training roles (not shown) provide facilities for 

dispatchers that simulate the actual system they will be using.

Records and 

Assets

Records and asset management roles track and report on the 

substation and network equipment inventory, provide geospatial data 

and geographic displays, maintain records on non-electrical assets, 

and perform asset-investment planning.

Operational

Planning

Operational planning and optimization roles perform simulation of 

network operations, schedule switching actions, dispatch repair 

crews, inform affected customers, and schedule the importing of 

power. They keep the cost of imported power low through peak 

generation, switching, load shedding, DER or demand response.
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Maintenance and 

Construction

Maintenance and construction roles coordinate inspection, cleaning, 

and adjustment of equipment; organize construction and design; 

dispatch and schedule maintenance and construction work; and 

capture records gathered by field technicians inform and perform 

their tasks.

Extension 

Planning

Network extension planning roles develop long-term plans for power 

system reliability; monitor the cost, performance, and schedule of 

construction; and define projects to extend the network, such as new 

lines, feeders, or switchgear.

Customer 

Support

Customer support roles help customers to purchase, provision, install, 

and troubleshoot power system services. They also relay and record 

customer trouble reports.

State Estimation

A process by which Network Calculation algorithms are applied to 

real-time measured parameters across the electrical grid to produce 

the information necessary to operate and optimize the system.

1
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1 A.5 - Generation Including DER Domain

2

3 Electricity generation is the process of creating electricity from other forms of energy and is 

4 the first process in delivering electricity to customers. This conversion may include a wide 

5 variety of primary energy resources and conversion technologies ranging from chemical 

6 combustion and nuclear fission, to flowing water, wind, solar radiation, and geothermal heat. 

7 As the primary electricity supply for the electrical grid, the Generation Including DER

8 domain is electrically connected to the Transmission or Distribution or Customer domain, 

9 and shares communications interfaces with the Operations, Markets, Transmission, and 

10 Distribution domains.

11

12

13 Figure 31 – Overview of the Generation Including DER Domain

14

15 Historically provided by large generators that fed only the high-voltage transmission system, 

16 the scalability and modularity of modern generating technologies alters the physical 

17 relationship and points of coupling between generation assets and the grid, as well as the 

18 distribution of generation assets. Accordingly, this domain has been updated to reflect direct 

19 electrical interconnection with the distribution system that smaller scale and distributed 

20 generation assets may utilize. The domain has also been renamed Generation Including 

21 DER.
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1 Communications with the Transmission and Distribution domains are critical, because 

2 without a delivery mechanism, customers cannot be served. The Generation Including DER 

3 domain should communicate key performance and quality of service issues such as scarcity 

4 and generator failure. These communications may cause the routing of electricity from other 

5 sources, or trigger an increased reliance on customer-cited measures described below. A lack 

6 of sufficient supply is addressed directly (via Operations) or indirectly (via Markets). 

7

8 For this revision, NIST has introduced a Customer Resources segment which includes an 

9 electrical flow that passes through the Generation Including DER domain to connect the 

10 Customer and Distribution domains. Aligning the Customer Resources electrical flow with 

11 the electrical flows from the broader set of generation resources is a visual indication of the 

12 growing participation of customer-sited generation resources in conventional settlement and 

13 dispatch processes. Initiating the customer resource in the Customer domain—which 

14 includes distributed generation, demand response, and other load-management technology—

15 reflects the growing number of market structures which treat demand management similarly

16 to generating capacity [163] and/or energy production [164]. Beginning the electrical flow in 

17 the Customer domain and terminating it on a secondary feeder in the Distribution domain 

18 highlights the unique physical conditions and control requirements for customer-sited 

19 resources when compared to conventional generation assets.

20

21 Communication are extremely critical to the increasingly pervasive DER at the bulk system 

22 and distribution levels, including behind-the-meter installations. The Generation Including 

23 DER domain has therefore been updated in this revision to explicitly identify necessary 

24 communications flows with the Distribution, Customer, and Service Provider domains. 

25 These external communications flows (shown as bidirectional arrows in Figure 31) represent 

26 the inter-domain communications flows previously drawn in Figure 4, and are not intended 

27 to describe specific interactions among roles or actors.

28

29 Evolving requirements for the Generation Including DER domain may include priorities such 

30 as controls for greenhouse gas emissions [165], increases in renewable energy sources [166], 

31 and provision of storage [167] to manage the variability of renewable generation or defer 

32 infrastructure obsolescence. To the extent that some of these goals require coordination 

33 across multiple domains, this complexity and associated interoperability requirements can be 

34 examined through the Conceptual Model communications flows. Roles in the Generation 

35 Including DER domain may include various physical actors, such as protection relays, remote 

36 terminal units, equipment monitors, fault recorders, user interfaces, and programmable logic 

37 controllers.

38

39 Examples of typical functions within the Generation Including DER domain that depend on 

40 communications flows and require interoperability are shown in Table 11.
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1 Table 11 – Typical applications requiring interoperability in the Generation Including DER 

2 domain

Example 

Application Description

Control

Performed by roles that permit the Operations domain to manage the 

flow of power and the reliability of the system. Currently a physical 

example is the use of phase-angle regulators within a substation to 

control power flow between two adjacent power systems.

Measure

Performed by roles that provide visibility into the flow of power and the 

condition of the systems in the field. In the future, measurement might 

be built into increasingly more discrete field devices in the grid.

Currently, an example is the digital and analog measurements collected 

through the supervisory control and data acquisition (SCADA) system 

from a remote terminal unit and provided to a grid control center in the 

Operations domain.

Protect

Performed by roles that react rapidly to faults and other events in the 

system that might cause power outages, brownouts, or the destruction of 

equipment. Performed to maintain high levels of reliability and power 

quality. May work locally or on a wide scale.

Record

Performed by roles that permit other domains to review what happened 

on the grid for financial, engineering, operational, and forecasting 

purposes.

Asset

Management

Performed by roles that work together to determine when equipment 

should have maintenance, calculate the life expectancy of the device, 

and record its history of operations and maintenance so it can be 

reviewed in the future for operational and engineering decisions.

3
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1 A.6 - Transmission Domain

2

3 Transmission is the bulk transfer of electrical power from generation sources to distribution 

4 through multiple substations (see Figure 32). A transmission network is typically operated 

5 by a transmission-owning utility, Regional Transmission Operator or Independent System 

6 Operator (RTO, ISO respectively), whose primary responsibility is to maintain stability on 

7 the electric grid by balancing generation (supply) with load (demand) across the transmission 

8 network. Examples of physical actors in the Transmission domain include remote terminal 

9 units, substation meters, protection relays, power quality monitors, phasor measurement 

10 units, sag monitors, fault recorders, and substation user interfaces.

11

12

13 Figure 32 – Overview of the Transmission domain

14 Roles in the Transmission domain typically perform the applications shown in the diagram 

15 (Figure 32) and described in the table (Table 12). The Transmission domain may contain 

16 DER, such as electrical storage or peaking generation units.

17

18 Energy and supporting ancillary services (capacity that can be dispatched when needed) are 

19 procured through the Markets domain; scheduled and operated from the Operations domain; 

20 and finally delivered through the Transmission domain to the Distribution domain and 

21 ultimately to the Customer domain.

22

23 A transmission electrical substation uses transformers to step up or step down voltage across 

24 the electric supply chain. Substations also contain switching, protection, and control 

25 equipment. Figure 32 depicts both step-up and step-down substations connecting generation 

Distribution

Storage

Substation Sag

Transmission

 

Substation

Control Measure Protect Record Stabilize Optimize

Operations Markets

Internal Communication Flows

Electrical Flows

Domain

External Communication Flows

Source: DRAFT NIST Smart Grid Framework 4.0

Generation including DER
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1 (including peaking units) and storage with distribution. Substations may also connect two or 

2 more transmission lines.

3

4 Transmission towers, power lines, and field telemetry (such as the line sag detector shown) 

5 make up the balance of the transmission network infrastructure. The transmission network is 

6 typically monitored and controlled through a SCADA system that uses a communication 

7 network, field monitoring devices, and control devices.

8

9 Table 12 – Typical applications in the Transmission domain

Example 

Application Description

Substation The control and monitoring systems within a substation.

Storage

A system that controls the charging and discharging of an energy 

storage unit to bridge temporal mismatches in supply, demand, and 

infrastructure capabilities.

Measurement & 

Control

Includes all types of measurement and control systems to measure, 

record, and control, with the intent of protecting and optimizing grid 

operation

10
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1 A.7 - Distribution Domain

2

3 The Distribution domain is the electrical interconnection between the Transmission domain, 

4 the Customer domain, and the metering points for consumption, distributed storage, and 

5 distributed generation (see Figure 33). As does the Generation including DER domain, the 

6 Distribution domain may contain DER, such as electrical storage, peaking generation units, 

7 or other medium-scale assets such as community solar installations. 

8

9 The electrical distribution system may be arranged in a variety of structures, including radial, 

10 looped, or meshed. The reliability of the distribution system varies depending on its structure, 

11 the types of configuration and control devices that are implemented, and the degree to which 

12 those devices communicate with each other and with entities in other domains.

13

14 Historically, distribution systems have been radial configurations, with little telemetry, and 

15 almost all communications within the domain was performed by humans. The primary 

16 installed sensor base in this domain was previously the customer with a telephone, whose call 

17 would initiate the dispatch of a field crew to restore power. Many communications interfaces 

18 within this domain have been hierarchical and unidirectional, although they now generally 

19 can be considered to work in both directions, even as the electrical connections are just 

20 beginning to support bidirectional flow. Distribution actors may have local inter-device 

21 (peer-to-peer) communication or a more centralized communication methodology. The use of 

22 higher speed communications to manage and optimize power flow and electricity generation 

23 and consumption in real time is an emerging concern for all stakeholders, particularly with 

24 higher penetration of DER (grid or behind-the-meter).

25

26 Figure 33 – Overview of the Distribution domain
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1 In the smart grid, the Distribution domain will have increased sensing and control capabilities 

2 and communicate in a more granular fashion with the Operations domain in real-time to 

3 manage the complex power flows associated with new technologies, a more dynamic 

4 Markets domain, and other environmental and security-based factors. In general this dynamic 

5 indicates a need for improving distribution system observability and awareness, and the 

6 Distribution domain model in Figure 33 has been updated to include additional sensing 

7 devices (e.g., fault circuit indicator) as well as domain operational functions (e.g., stabilize) 

8 which had been limited to the Transmission domain in previous Conceptual Models. 

9

10 The Markets domain will communicate with the Distribution domain in ways that will affect 

11 localized consumption and generation. In turn, these behavioral changes due to market forces 

12 may have electrical and structural impacts on the Distribution domain and the larger grid. 

13 Under some models, service providers may communicate with the Customer domain using 

14 the infrastructure of the Distribution domain, which would change the communications 

15 infrastructure selected for use within the domain.

16

17 It should be noted that DER can be considered both a Transmission and Distribution asset, so 

18 the model has been updated to reflect this reality from the electrical and communications

19 standpoints. Examples of typical application categories in the Distribution domain are in

20 Table 13.

21

22 Table 13 – Typical applications within the Distribution domain

Example 

Application Description

Substation The control and monitoring systems within a substation

Storage

A system that controls the charging and discharging of an energy 

storage unit to bridge temporal mismatches in supply, demand, and 

infrastructure capabilities.

Distributed 

Generation A power source located in the Distribution domain of the grid.

Non-Wires 

Alternatives

DER, either individually or aggregated, that are used to replace or 

defer distribution infrastructure upgrades.

Measurement & 

Control

Includes all types of measurement and control systems to measure, 

record, and control power flows, with the intent of protecting and 

optimizing grid operation.

23
116

1 Appendix B – Mapping CPS Aspects and Concerns to the Electrical Grid

2

3 This appendix presents the evaluation of grid context for the existing set of CPS concerns as described in Section 2.3. Note that the Description column in Table 14 contains a summary of the 

4 concern as defined in the CPS framework, and has been included here verbatim from that document. The “Architecture Significance” column provides some examples of how each concern 

5 relates to activities or emerging trends in power systems, as well examples of changes that could arise as new architectures are introduced. The architecture significance column therefore may 

6 help clarify the importance of CPS concerns to the electrical grids of today and tomorrow.

7

8 Table 14 – Mapping CPS Aspects and Concerns to the electrical grid

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Functional Actuation Concerns related to the ability of the 

CPS to effect change in the physical 

world.

• Geographic separation between power generation and its 

use requires sufficient electric transmission and improved 

bulk power control systems, including structural changes to 

existing systems to better manage the increasing fast grid 

dynamics and rising influence of distribution systems in bulk 

system operations.1 In addition, the increased role of 

distribution grids requires greater coordination between 

premise, distribution, and bulk control systems and their 

operators.

• Examples of new and anticipated control capabilities to 

address these power system actuation needs include better 

managing electric vehicle (EV) impact by monitoring and 

controlling EV chargers, and reconfiguring circuits using 

automatic circuit configuration, e.g. FLISR.

Ability to impact the power 

flow throughout the grid, 

including sources and load, by 

means of controlled, often 

remote, actuation of power 

systems equipment.

• To support overall grid system control through 

improved actuation capabilities, distribution systems 

are likely to need additional capabilities such as 

situational awareness and algorithms, previously 

needed only for transmission systems, e.g. state 

estimation. 

• To optimize distribution systems for new 

capabilities such as managed/smart EV charging and 

automatic circuit reconfiguration, projections of EV 

demand and generation levels and implementation of 

new Protection and Relay schemes that effectively 

respond to grid events are needed.
117

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Functional Communication Concerns related to the exchange of 

information internal to the CPS and 

between the CPS and other entities.

•Architecture concerns include sharing of infrastructure for 

communications.33 

• Legacy communications systems are widely deployed, 

trusted, tested, and represent billions of dollars of 

investment, thus transition to modern communications is 

likely to occur over an extended time period.

Exchange of information 

between internal and external 

networks including 

communications protocols, the 

communication network, and 

the exchange between 

interested parties. 

• Additional sensors and wider-geographic area 

communications systems are needed to support the 

broad range of new functional communications 

requirements, including for enhanced situational 

awareness at the Distribution level. 

• Use of public communications networks will likely 

increase. 

• The addition of new distribution automation 

devices/intelligent electronic devices/meters will 

require more communications capabilities, e.g. higher 

bandwidth.

•Architecture must support both rapid and slow 

transitions from legacy SCADA over IP 

devices/communications. 
118

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Functional Controllability Ability of a CPS to control a 

property of a physical thing. There 

are many challenges to 

implementing control systems with 

CPS including the non-determinism 

of cyber systems, the uncertainty of 

location, time and observations or 

actions, their reliability and security, 

and complexity. Concerns related to 

the ability to modify a CPS or its 

function, if necessary.

• Controllability requires coordination of sensing, processing 

and acting.

• Multiple inputs, including from multiple systems, are 

needed to inform control decisions.

• Most grid control systems and hardware were not designed 

to accommodate large numbers of distributed energy 

resources (DERs).

• More dynamic monitoring and control is needed to be able 

to respond to dynamic grid conditions.

Ability to control grid 

properties (sense, process and 

change); e.g., intentionally 

change a property. 

• To provide the required controllability, distribution 

systems are likely to need situational awareness and 

algorithms previously only needed for transmission 

systems, e.g. state estimation.

• Coordination of sensing and processing functions is 

needed to produce accurate control signals.

• Architectures may need to support control 

applications that use multiple optimization factors 

including those based on carbon usage and market 

prices.

• Architectures may need to support use of group 

commands (e.g., DNP3 settings groups) and thirdparty aggregator control of DERs.

• Architecture support of faster input of sensor data 

from traditional SCADA devices and newer devices 

including phasor measurement units (PMUs) is 

needed.

Functional Functionality Concerns related to the function that 

a CPS provides.

• The constant evolution of the power system requires 

continual development and integration of new grid 

functionality.

• Grid control functionality has expanded to include 

increased management of generation assets, including with 

diverse ownership, varying control capabilities, and 

distributed locations, all of which require different control 

functionality.

Ability to provide grid 

functions, e.g. control 

functions, sensing functions, 

service-related functions.

• Innovative grid technology is needed to facilitate 

development and implementation of a range of new 

grid functionalities, including in power markets, 

DERs, microgrids, Electric Vehicles, and others.

• Architecture needs to support management of DERs 

with new control capabilities that differ from that of 

older types of generation. 

Functional Manageability Concerns related to the management 

of CPS function. 

• New functionalities are needed to improve effective 

management of an ever-changing portfolio of devices and 

systems that are deployed and operated at different grid 

levels.

Ability to develop and 

implement new functionality to 

manage change internally and 

externally to the grid.

• Communication topology views and key externally 

visible properties based on multi-tier distribution 

communications are needed for system control, 

substations, field operations, and 

Transmission/Distribution integration.74
119

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Functional Measurability Concerns related to the ability to 

measure the characteristics of the 

CPS.

• Changing dynamics of the grid require faster measurement 

of grid characteristics to gain visibility and situational 

awareness needed to enable active management instead of 

historically passive approaches, e.g. through physical inertia 

of generation.

• SCADA systems typically report data at slow rates, e.g. 

once every 4 seconds, compared to new IoT control systems 

that can operate in the millisecond or microsecond 

timeframe.

• Behind the meter (BTM) generation is typically not 

measured. 

Ability to quantify a 

phenomenon / property against 

a known reference or 

fundamental definition.

• Architecture needs to support applications and 

sensors with a broad range of data rates.

• Behind the meter (BTM) generation can be 

characterized through measurements with separate 

meters, or by using other techniques to estimate nonmetered generation.

Functional Monitorability Concerns related to the ease and 

reliability with which authorized 

entities can gain and maintain 

awareness of the state of a CPS and 

its operations. Includes logging and 

audit functionality.

• Increasing complexity of bulk energy systems, combined 

with reduced operating margins, results in new and more 

complicated grid control issues8 and increased need for 

multi-tier situational awareness.

• Additional visibility and monitoring, including to better 

forecast supply and demand, is needed to support increased 

deployment of prosumer systems, which both use and 

generate electricity and may be located behind the meter. 

• Distribution state estimation will require consistent 

monitoring of measured distribution grid data to be useful.

Measuring a property over a 

period of time.

• Architecture support will be needed for increased 

input of grid sensor data and control messages, 

including DER.

• Improved forecasting algorithms will be needed that 

use historical prosumer net load or generation as well 

as near-real time production data.

• State Estimation algorithms that produce consistent, 

accurate results will be needed.

Functional Performance Concerns related to whether a CPS 

can meet required operational 

targets.

• Geographic and temporal mismatches between supply and 

demand are growing in some areas.

• Energy efficiency and overall energy use of ubiquitous IoT 

devices, when powered using alternating current (AC) 

power, may be improved by taking advantage of the 

capability to run natively on direct current (DC) power to 

avoid losses due to AC-DC conversion.

Ability to deliver power as 

required by consumers.

• Architecture support is needed to provide additional 

balance between supply and demand, for example, 

supporting installation of DERs with Energy Storage 

in areas with challenges to support increased DER.

• Architecture advances are needed to support new 

DC networks, such as in homes and commercial 

buildings, for lighting systems, electric vehicles, and 

distributed solar PV systems. 
120

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Functional Physical Concerns about purely physical 

properties of CPS including seals, 

locks, safety, and EMI.

• Grid devices and systems have specific physical 

requirements for operation, protection, and safety.

• There are requirements for hardening of devices, e.g., 

physical enclosure, immunity to EMI, and others. 

Ability to ensure proper 

physical configuration in the 

operating environment.

• For architectures in which the active operating 

environment is designed to extend further towards the 

edge of domains, proper configuration and physical 

properties of new assets must be assured (e.g., edge 

devices may need additional physical security to 

ensure consumer safety).

Functional Physical 

Context

Concerns relating to the need to 

understand a specific observation or 

a desired action relative to its 

physical position (and uncertainty). 

While this information is often 

implied and not explicit in 

traditional physical systems, the 

distributed, mobile nature of CPS 

makes this a critical concern.

• The physical context, including geographical location of 

the device in the system as well as its location in the 

topology, is important for managing functional capabilities 

including monitoring and control.

• The need for local optimization of grid assets increases 

with physical decentralization of distributed resources 

towards the edges of systems. Increased congestion (e.g. at 

the edge) may affect operations of aging infrastructure when 

load reaches or exceeds the originally designed physical 

limits of distribution systems.

Concerns relating to the need 

to understand information on 

the geographic and topological 

location of the physical asset. 

• Architecture element will need to include physical 

location as well as network location for the devices.

• Architectures should accomodate temporal changes 

in physical context as new asset deployments and 

system contingencies impact topology.

Functional Sensing Concerns related to the ability of a 

CPS to develop the situational 

awareness required to perform its 

function.

• Internet of Things (IoT)-related grid technology changes 

include small systems and solutions rather than large 

centrally controlled solution, flexible solution rather than 

fixed solutions, and wireless communications increasingly 

used whenever possible.18

• Increasing complexity of the grid may impact the ability to 

sense grid conditions and status.

Ability to detect a property of 

the electrical grid over time.

• Additional smart devices and distributed sensors are 

needed to increase the level of information, 

monitoring, and control at various points of the 

distribution system.

• Sensors and communications for distribution 

observability are needed to be architected as core 

infrastructures. 73
121

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Functional States Concerns related to the states of a 

CPS. For example, the functional 

state of a CPS is frequently used to 

allow for variation in the CPS 

response to the same set of inputs. 

Variation in response based on state 

is sometimes referred to as 

functional modes.

• State estimation is one of the most important functions 

performed by system operators, and its use is extending from 

the bulk system to distribution systems. Proper state 

estimation allows control signals to be adjusted to optimize 

system operations and economics, and is important to 

maintaining system reliability and resilience by ensuring 

contingencies are available and activated when grid systems 

are operated beyond the designed capabilities or fail.

• The proliferation of connected devices and systems in the 

grid will introduce new capabilities and provide new input 

data for state estimation. This will also require greater 

situational awareness across the system.

• The ability to monitor and control devices is critical in the 

modernized grid.

Concerns related to the ability 

to know the operating status 

and conditions of the grid and 

connected assets.

• Architectures must clearly identify which smart 

devices and sensors are important to state estimation, 

what information is required from those devices, and 

how that information should be communicated.

• As the granularity of state estimation changes over 

time, architecture elements should define the systems 

with which smart devices must communicate 

operational and state information.

• Smart devices and sensors with multiple capabilities 

can affect the ability to measure local system states, 

and networked devices can impact state estimation 

across wider areas. With increasing technological 

diversity, communications about operating status 

must match the needs and informational capacity of 

the interfacing systems.

Functional Uncertainty Managing the effects of 

uncertainties is a fundamental 

challenge in CPS. Sources of 

uncertainty in CPS can be grouped 

into statistical (aleatoric), lack of 

knowledge (epistemic) uncertainty, 

or systematic uncertainty. In CPS, 

statistical uncertainty is caused by 

randomness of accuracy of sensing 

and actuation, often caused by 

uncertainty of manufacturing 

processes. Systematic uncertainty is 

caused by incomplete knowledge 

either due to limits of acquired 

knowledge or due to simplification 

in modeling. Typical manifestations 

of epistemic uncertainty are limited 

validity of models of physical 

processes or limits of computability 

of properties of mathematical 

models.

• Fundamental limitations in the spatial and temporal ability 

to observe the electrical grid create uncertainty between 

model forecasts and actual operations. As sensors are 

deployed that can observe previously unmonitored aspects of 

the grid, this uncertainty can be minimized. Uncertainty can 

be reduced but not fully eliminated for a system as large and 

complex as the electric grid.

• High penetration of variable generation renewable 

technologies and other DERs broadens the drivers of 

uncertainty that must be accounted for by grid operators.

• Improved understanding of uncertainty propagation would 

benefit grid operators.

Concerns related to the ability 

to characterize and mitigate 

uncertainty in the system for 

improved operations. Sources 

of uncertainty in the grid can 

include forecast error; 

randomness of individual 

actions affecting supply, load, 

or infrastructure; sensor 

limitations; and incomplete 

knowledge of the system.

• Architecture elements will need to include 

uncertainty thresholds related to operational schemes.
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Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Business Cost Concerns related to the direct and 

indirect investment or monetary 

flow or other resources required by 

the CPS throughout its lifecycle.

• Different amortization schedules exist for grid components, 

such as for generation, which for solar generation can range 

from 6 years or less, compared to 20 years or more for other 

generation assets. 

• The financial environment for grid investments, including 

capital expenditures (capex) and operation, maintenance and 

monitoring (OMM) expenditures, affects utilities’ business 

practices and decisions broadly, from viability and 

bankability of individual projects to potential long-term 

underinvestment in grid operations and maintenance.

Direct and indirect lifecycle 

costs of electric grid 

components.

• Consideration of grid asset uniqueness with respect 

to amortization schedules.
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Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Business Enterprise Concerns related to the economic 

aspects of CPS.

• Grid control algorithms will likely increase in complexity 

in order to manage market economics, efficient energy 

usage, and reliability factors based on an increasing variety 

of resources, such as storage and demand response resources 

in areas with high penetrations of wind and solar generation.

• Investments in energy production (generation) and delivery 

infrastructure generate a return on investment for utilities 

and energy producers; grid infrastructure enhancements need 

to also produce economic value or they will not be built. 14

• Architecture concerns include network convergence and 

transition from economies of scale to network economies. 35

• Increasing dynamic grid conditions will require more 

dynamic markets.

• New distribution-level markets and market structures are 

likely to be created, including the introduction of 

Distribution System Operators (DSOs) to manage 

distribution system operations and maintain reliability and 

increase resilience under much higher levels of uncertainty 

and complexity.

Long term economic viability 

of maintaining the grid.

• The Distribution grid of the future may be designed 

as an open–access network for energy transactions.75

• Architecture and enhanced communications are 

needed to enable new transactive energy approaches 

to distribution grid coordination and control.77

• Economic and societal benefits of architecture 

changes must be quantifiable to support rigorous 

regulatory/stakeholder analyses to secure authorized 

funding. 

• Network convergence of electric, gas, and water 

distribution, traffic lights, emergency services, and 

public safety systems is likely to increase 

development of common platforms for sensing, 

communications, and control.44

• New Transactive Energy Market architectures are 

needed.

• Architecture support is needed to enable 

development and implantation of algorithms that 

incorporate uncertainty (unpredictability) and 

complexity.

• Transparent market/economic business models 

should be developed to understand business factors 

that are driving decisions.

Business Environment Concerns related to the impacts of 

the engineering and operation of a 

CPS on the physical world.

• Outcome-oriented or performance-based regulation, 

including, for example, Performance Incentives Mechanisms 

(PIMs), have the potential to align utility motivations with 

societal goals related to the environment.

Concerns related to the impacts 

of the engineering and 

operation of the grid on the 

physical world.

• Architecture support is needed to enable systemlevel consideration of additional environmental 

factors (e.g., carbon use) in addition to economics.
124

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Business Policy Concerns related to the impacts of 

treaties, statutes, and doctrines on a 

CPS throughout its lifecycle.

• Increased use of renewable energy is being required by 

legislation in many states.9 including Hawaii, which is 

requiring 100% renewable usage by 2040, and California 

(50% by 2030) and Vermont (75% by 2032).10 In addition, a 

growing number of large corporations (including Google, 

Apple, and Amazon) are stating that their goal is 100% 

renewable energy use. 

Concerns related to grid 

policies such as enterprise 

goals (e.g. adherence to 

established standards and 

protocols) or societal goals 

(e.g., renewable portfolio 

standards).

• Architecture support is needed to enable new 

operational system controls for systems with high (up 

to 100%) renewable energy usage. Currently key 

operational considerations include use of significant 

amounts of battery storage, and use of advanced DER 

generation assets with new functionality.

Business Quality Concerns related to the ease and 

reliability of assessing whether a 

CPS meets stakeholder (especially 

customer) expectations.

• Customer expectations are changing as customers become 

increasingly aware of energy issues and also want ease of 

interaction with utilities and energy services providers based 

on their experiences with mobile phones, banking systems, 

and other modern conveniences.

• The emergence of new types of local energy choice and 

formation of community energy related entities (community 

choice aggregation/CCAs, community “solar garden” coops, etc.) will require operational changes in control systems 

to maintain customer quality expectations.34

Concerns related to customer 

satisfaction or perceived 

quality of grid services.

• Coordination structures and customer outreach are 

needed to facilitate integration of community energy 

resources such as multi-user microgrids and solar 

gardens into overall resilience strategies.68

• New hybrid central/distributed control structures are 

needed for enhanced distribution control to facilitate 

functional flexibility and grid resilience.45

• New concepts in grid architecture (e.g. potential for 

city distribution grid to support an open–access 

network for energy transactions46 ) will require 

significant customer outreach to ensure quality of 

energy services is maintained.
125

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Business Regulatory Concerns related to regulatory 

requirements and certifications.

• Many state regulatory bodies are developing grid 

modernization guidance for distribution utilities in their 

jurisdictions (NY – NY REV, CA – MTS, MN – E21, OH –

PowerForward, etc.).43 Such regulatory guidance, and more 

generally the overall practices and environments of 

individual state commissions, have significant effects on the 

asset investment strategies and business models of grid 

participants.

• Utilities with large geographic extent may be under the 

jurisdiction of several Public Utility Commissions (e.g. in 

different states) and may face additional difficulties in 

developing and deploying enterprise-wide solutions while 

meeting expectations of multiple regulatory bodies.

• Renewable energy goals may be articulated at a high level 

such that the connection to specific grid changes necessary 

to meet the goals is not well understood.12 

• Utilities and energy service providers working with 

governmental organizations, such as cities, need to work 

work within local regulatory systems and authorities, and 

understand local conditions such as a city’s budget 

management needs and processes for financing new 

projects.37

• The electric grid directly supports many other 

infrastructures, such as transportation, waste management, 

and public safety, that are critical to the creation of safe and 

efficient urban environments in smart cities. 38 

Concerns related to the 

regulatory oversight of the 

grid.

• Additional standardization of interfaces across US 

Distribution System Operators (DSO) may be helpful 

to reduce level of effort needed to implement DSOs 

nationwide, including under differing regulatory 

environments. 

• Significant operational architecture support is 

needed for design and implementation of 100% 

renewable systems.

• Architecture support needed to design grid systems 

for which one can calculate costs (e.g. on a year-byyear basis) to support budget analysis needed for 

regulatory oversight.

• Integrated electric grid and smart city architecture is 

needed to support effective integration of 

infrastructures.

• Market architecture and economic models are 

needed that support value exploration and 

communications between regulators and 

utilities/energy sector participants, including to 

consider costs and economic benefits of new assets 

such as DER.
126

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Business Time to Market Concerns related to the time period 

required to bring a CPS from need 

realization through deployment.

• There is an overall mismatch between speed to market of 

information technology compared to operational technology 

in the energy sector. An illustration of this mismatch is 

found in a comparison of typical 30-year innovation cycles 

and depreciation schedules in utilities with typical 3-year

innovation cycles and depreciation schedules in 

telecommunications companies. 

• Technical barriers to DER integration with utility control 

systems, and high costs of DER interconnections including 

costs of connection to utility communications network, can 

lead to delayed time to market.

Concerns related to the time to 

implement new grid 

technology from realization to 

deployment within the 

constraints of legacy systems.

• Telecommunications and other non-utility 

communications and interoperability solutions are 

likely to be implemented on a shorter time scale, 

followed later by utility solutions. Thus, architectures 

are likely to be impacted more quickly by non-utility 

solutions and should accommodate different 

development time cycles. 

• To reduce time to market for new innovative 

products, standardization of utility-DER interfaces 

and interconnections are needed, including support 

for automated interconnection applications for 

consumers.

Business Utility Concerns related to the ability of a 

CPS to provide trusted benefit or 

satisfaction through its operation. 

Utility reflects a business concern, 

especially when considered as the 

numerator when computing value, 

which equals utility divided by 

costs.

• Additional information is needed to understand the 

comparative value provided by installed infrastructure, 

T&D, or customer owned assets.

• New energy services (volt/VAR, synthetic inertia, demand 

response, storage, etc.) will provide expanded range of 

sources of usefulness (value).

• Significant changes in energy cost by source have occurred 

in recent years. For example, the lowest levelized cost of 

energy from any source (without subsidiaries) is now wind 

followed by utility-scale solar PV.88

• In order to realize all DER benefits, distribution planning 

should consider use of DERs as an option.

• Different business models of vendors, commercial control 

system developers, generation owners, and utilities (which 

themselves have multiple business models for IOUs, 

municipalities, co-ops, government-owned utilities) and 

different understandings of utility (business value) may 

impede collaborations. For example, unmetered Behind the 

Meter (BTM) generation may not be accurately valued.

Ability to reliably supply 

electric power (as a business 

value) to consumers.

• Assessment of least cost alternative should include 

new infrastructure, customer-owned assets, and nonwires alternatives such as Demand Response.

• New Distribution feeder structures are needed to 

facilitate adaptation to stress conditions and sharing 

of localized energy resources.64

• Assessment of least cost alternative should consider 

multiple revenue streams from DER and other nonwires alternatives, including energy shifting, load 

shifting, ancillary services and reliability 

improvements/impacts.

• Distribution planning applications should consider 

DER assets in the set of potential options for new 

projects 

• New regulatory tariffs will require BTM and other 

systems to include the ability to schedule services, 

e.g. battery’s ability to provide energy at specific 

time periods, based on tariffs91 e.g., Time of Use 

(TOU) rates.
127

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Human Human Factors Concern about the characteristics of 

CPS with respect to how they are 

used by humans.

• Some stakeholders have difficulties in understanding what 

a kWh is or its economic value, which may prevent 

consumers from effectively participating in market 

constructs that deal in kWhs or MWhs. Without needed 

context and information, consumers “have a hard time 

estimating the costs and benefits of their actions.” 13 

• Consumer choice including local energy choice29 are 

among the primary factors driving increased automation with 

large amounts of DER.

• Architecture concerns related to human factors range from 

system operator ergonomics to interaction/convergence with 

social networks and social media.36 These concerns, and 

additional concerns related to human performance, also 

apply to human operators in grid control center 

environments

Ability of power system users 

to understand and respond to 

grid concepts, functions and 

operational requirements.

• Value propositions (including regulatory tariffs) are 

needed in which benefits and costs are clear to 

consumers and presented at the time that consumer 

decisions are anticipated to be made.

• Additional consumer education is needed to support 

consumers to select their energy providers (if 

available), to select an option to request all renewable 

energy, and to join with others to form Community 

Choice Aggregation (CCA) districts.

• Human factors assessments and inputs in 

application development process are needed, 

including for example, evaluation of human factor 

concerns in control centers to improve the 

performance of humans-in-the-grid-control-loops. 

Architectural support is needed for development of 

interfaces with social media, including to provide 

easy-to-understand energy price information and 

outage status to customers.

Human Usability Concerns related to the ability of 

CPS to be used to achieve its 

functional objectives effectively, 

efficiently, and to the satisfaction of 

users (adapted from ISO 9241-210.) 

The combination of physical and 

cyber into complex systems creates 

challenges in meeting usability 

goals. Complexity is a major issue. 

The diversity of interfaces creates a 

significant learning curve for human 

interaction.

• Improved (simpler/better/intuitive) user interfaces are 

needed to support human-grid interactions. For example, the 

inability (and disinterest) of humans to manually control 

grid-connected equipment requires user-friendly interfaces 

(and effective automation) to help manage these devices, e.g. 

potentially millions of DERs, in coordination with grid 

management systems.

• Situational awareness applications are needed to improve 

system visibility and usability for consumers, market 

management organizations, market participants, utilities and 

other stakeholders.

Ability of power system users 

to understand, interact with, 

and apply grid technology.

• Improved interfaces including preset or interactive 

device level controls, as well as aggregation of DER 

assets, can be used to increase usability and reduce 

need for direct control of each DER. Such interfaces 

would help to reduce human-based concerns about 

difficulties and complexity of managing gridresponsive equipment.

• Architecture support is needed for effective delivery 

of relevant data to stakeholders to include consumers, 

market management organizations, market 

participants and utilities.
128

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Trustworthiness Privacy Concerns related to the ability of the 

CPS to prevent entities (people, 

machines) from gaining access to 

data stored in, created by, or 

transiting a CPS or its components 

such that individuals or groups 

cannot seclude themselves or

information about themselves from 

others. Privacy is a condition that 

results from the establishment and 

maintenance of a collection of 

methods to support the mitigation of 

risks to individuals arising from the 

processing of their personal 

information within or among 

systems or through the manipulation 

of physical environments.

• The availability of high-frequency energy usage data 

collected for the purpose of energy monitoring may facilitate 

the unintentional release of private, confidential information.

For example, the data has the potential to reveal information 

about an individual’s behavior, such as when he or she 

arrives home at night, and what are his or her general day-today interactions with CPS systems.39

• Collecting pieces of information from various sources and 

then using algorithms or machine learning to analyze this 

information, makes it possible to combine “safe” (privacyprotected) data from many sources to create “unsafe” results 

that reveal confidential information about individuals (e.g. 

privacy concerns). 

• An additional privacy concern is simply one of 

confidentiality of customer data, including data of 

commercial and industrial customers.

Concerns related to the ability 

of the grid to prevent entities 

(people, machines) from 

gaining access to data stored 

in, created by, or transiting a 

CPS or its components such 

that individuals or groups 

cannot seclude themselves or 

information about themselves 

from others. Privacy is a 

condition that results from the 

establishment and maintenance 

of a collection of methods to 

support the mitigation of risks 

to individuals arising from the 

processing of their personal 

information within or among 

systems or through the 

manipulation of physical 

environments.

• Methods and algorithms can be developed for 

removing Personally Identifiable Information (PII) 

and sensitive personal information (SPI) from 

monitored electric usage data.
129

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Trustworthiness Reliability Concerns related to the ability of the 

CPS to deliver stable and 

predictable performance in expected 

conditions.

• Reliability can be understood as the ability of the electric 

power system to deliver electricity in the quantity and with 

the quality needed to satisfy demand, typically measured by 

interruption indices appropriate for normal operation. 

• Increased onsite generation (including renewables and 

backup generation), often in the context of a user-controlled 

microgrid, is a common approach by customers to address 

their own site-specific concerns about reliability. These 

assets may also be aggregated and can participate in markets 

to provide compensated grid reliability resources. 

• The reliability of intermittent/non-dispatchable DERs (as 

individual generation assets) can significantly impact the 

reliability of the connected grid system. 

Concerns related to the ability 

of the grid, or components 

within a grid, to deliver stable 

and predictable performance in 

expected conditions.

• If assets other than those owned by the utility are 

trusted and compensated to support grid reliability, 

what happens if reliability norms are violated (e.g. 

how is the utility or other affected parties informed), 

and how would organizations be responsible for the 

localized and regional impacts of the violation?

• The ability of grid segments or devices, possibly 

owned by groups other than the utility, to provide 

autonomous corrections to system operation (i.e., 

those corrections not controlled by the central utility) 

will reduce communications requirements and 

associated costs for deploying DER, and also increase 

the speed with which corrective action can be taken 

throughout the system. An example of this is the 

automated function of reclosers. 

• Multi-user microgrids and microgrid networks may 

require coordination with distribution grids and need 

for microgrid-to-grid services.47

• A lack of verified reliability for individual asset 

performance could lead grid operators and/or utilities 

to require direct observability of asset behavior, 

especially when controllable assets are grouped to 

provide specific operational characteristics through 

processes opaque to the utility.
130

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Trustworthiness Resilience Concerns related to the ability of the 

CPS to withstand instability, 

unexpected conditions, and 

gracefully return to predictable, but 

possibly degraded, performance.

• Different from reliability, in which normal services are 

provided, resilience includes the ability to prepare for and 

adapt to changing circumstances, and to withstand and 

recover rapidly from disruptions. Resilience may include a 

graceful degradation of performance. The interconnected 

nature of grids means degradation will likely affect more 

than just those stakeholders which negotiated (or agreed to) 

the degraded operating solution. The authority to determine 

the operating solution had previously resided with utilities 

and similar load serving entities; the significance of 

assigning these decisions to others is not yet clear.

• The determination (or negotiation) of the degraded state is 

an unclear process right now, and care must be taken to 

ensure all stakeholders can participate and have their 

interests represented accurately in the final solution.

• When trustworthy resilience is provided by operating in a 

degraded state, the necessary communications to external 

entities must be clarified.

• Scientific studies indicate that extreme weather events such 

as heat waves and large storms are likely to become more 

frequent and intense53 increasing risk of damage to electric 

grid infrastructure. 

• For many industries, a momentary outage of 15 seconds, or 

an extended outage of 15 hours, results in the same 

economic loss.5

Concerns related to the grid, or 

components within a grid, to 

withstand instability, 

unexpected conditions, and 

gracefully return to 

predictable, but possibly 

degraded, performance.

• Coordination, communication, and sensing 

structures that facilitate use of Distributed Generation 

(DG) for grid resilience purposes are needed.66

• Grid and communication/coordination structures 

that enable fast use of the results of contingency 

planning are needed.65

• Condition-Based Maintenance (CBM) projects 

require additional communications bandwidth.

• Storage at the distribution level can be used to 

improve resilience.76

• Effective use of smart meters at high-priority sites 

(such as hospitals and first stations) with enhanced 

outage detection alerts requires faster higher 

bandwidth communications networks.

• Electric Vehicles charging may be able to provide 

additional resilience support for grid systems, in 

addition to meeting customer charging needs.
131

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Trustworthiness Safety Concerns related to the ability of the 

CPS to ensure the absence of 

catastrophic consequences on the 

life, health, property, or data of CPS 

stakeholders and the physical 

environment.

• Utilities and energy service providers/operators ensure that 

safety is prioritized within their operations and for the 

protection of customers. 

• Potential impacts on safety arise from multiple concerns, 

many of which are grouped in Trustworthiness. For example, 

the potential for device (and substation) controllability to be 

compromised through malicious intent via a cybersecurity 

attack can have catastrophic life-safety implications.

• Safety must be evaluated and maintained or improved 

throughout all grid system evolution processes. For example, 

as distributed devices are increasingly deployed to enhance 

system reliability and resilience, traditional safety practices 

may no longer be relevant and must be updated.

Concerns related to the ability 

of the electrical grid to ensure 

the absence of catastrophic 

consequences on the life, 

health, and property due to 

electrical hazard to consumers, 

installers, and maintenance 

workers.

• Dynamic reorganization of system architectures to 

provide the greatest level of system performance and 

net economic benefit will create uncertainties in 

status and safety requirements as workers from 

multiple organizations work to restore what could be 

competing architectures of service.
132

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Trustworthiness Security Concerns related to the ability of the 

CPS to ensure that all of its 

processes, mechanisms, both 

physical and cyber, and services are 

afforded internal or external 

protection from unintended and 

unauthorized access, change, 

damage, destruction, or use.

• Most substation systems were designed as isolated nonconnected systems. Thus, connecting IoT-enabled devices 

and systems within substations requires reevaluation of 

security concerns, including implementation of device-level 

cybersecurity in addition to other measures. 

• Adding cybersecurity later, which is required for most 

legacy substation and field devices, typically results in less 

effective security than designing in and implementing 

cybersecurity at the beginning. 

• A timing-denial cyber-attack could be conducted either via 

Global Navigation Satellite System (GNSS) denial or using 

interference with communications network traffic. Such an 

attack could lead to a grid or substation failure.22

• A spoofing cyber-attack could be initiated by any device 

connected to a substation communications bus (including 

those only temporarily connected), or via an external device 

that reaches the substation via a poorly protected gateway. 

Such an attack would provide individual or all subsystems 

with false time, therefore resulting in an infringement of 

local or global time synchronization.23

• Denial of Service (DoS) cyber-attacks over extended time 

periods could lead to grid or substation failures. 24

• Proliferation of additional DER and distributed automation 

devices requires additional physical security to protect these 

assets. 

Concerns related to physical 

and cyber processes and 

mechanisms impacting 

trustworthiness. 

• Architecture for resilience buffering against edge 

device induced power flow volatilities is needed for 

defense against IoT-based cyber-attacks.81

• Cybersecurity architecture is needed to address the 

inherent risks of connecting devices to a network/the 

Internet.

• Security architecture is needed to address multiple 

concerns, including for DERs, and to protect against 

timing-denial and DoS cyber-attacks, and to protect 

substations against spoofing attacks. In addition, 

security architecture for securing legacy electric grid 

systems and securing substations is needed. Security 

architecture is also needed to support input and 

monitoring of physical devices, and for transactive 

energy.

• Distribution-level cyber securability approaches are 

needed for information flow, coordination, and 

control that are inherently defendable.79
133

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Timing Logical Time Concerns related to the order in 

which things happen (causal order 

relation) or event driven.

• Protection and safety schemes for the grid require 

sequential operation in time and close coordination across a 

number of physical events and actuations. 

• As grid automation increases, especially on distribution 

systems, these coordinated and sequential operations will 

become more common within—and important to—daily 

operations and system optimization.

• Hardware in the loop testing and simulation is prevalent 

among grid operators, especially for modeling distributed 

energy resources in the system. These efforts depend on 

logical time steps that enable faster-than-real-time 

simulation and are conducive to meeting the operational and 

planning needs of various grid stakeholders.

Concerns related to the ability 

to specify and coordinate time 

sequences for operations, 

simulation and testing.

• Architecture is needed to support logical time 

sequencing to meet operational, testing, and 

simulation requirements.

Timing Synchronization Concerns for synchronization are 

that all associated nodes have timing 

signals traceable to the same time 

scale with accuracies as required. 

There are three kinds of 

synchronization that might be 

required: time, phase, and frequency 

synchronization, although frequency 

synchronization is also called 

syntonization.

• The increasing importance of coordination across the 

transmission and distribution systems results in greater need 

for synchronization on more granular time scales and 

accurately disseminated over larger physical areas.

• Maintaining integrity of time synchronization is can be 

difficult because reference sources and communication 

mediums are subject to interruption and failure. For 

example, loss of GPS timing synchronization for 

Supervisory Control and Data Acquisition (SCADA) 

systems and synchrophasors data can compromise grid state 

estimation and impact the situational awareness and control 

capabilities of the power system. Redundant time 

synchronization systems provide benefits of continuity of 

timing infrastructure during such interruptions and failures. 

• Awareness and seamless mapping of different time scales 

and local time are needed to accommodate adjustments (e.g., 

introduction of leap seconds and daylight savings time)

Concerns that all nodes and 

devices connected to the grid 

have timing signals traceable 

to the same time scale with 

accuracies as required.

• Synchronized timing allows for localized data 

analytics and simpler data communications.

• Communication infrastructures for timing and 

alternatives (redundant systems) are needed for 

timing distribution over distribution grids, in 

conjunction with or independent of satellite-based 

methods.80

• Architecture is needed to support applications 

ability to rely on accurate time stamps while 

recognizing that they can be subject to interruptions 

and communications failures.

• Architecture support is needed to facilitate 

applications to recognize and account for timing 

issues including different time zones, local time and 

daylight savings, as well as technical time 

synchronization issues such as introduction of leap 

seconds.
134

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Timing Time 

Awareness

Concerns that allow time 

correctness by design. The presence 

or absence of time explicitly in the 

models used to describe, analyze, 

and design CPS and in the actual 

operation of the components. This is 

a life- cycle concern as well as a 

concern for the ability to build 

devices without the need for 

extensive calibration of the timing 

properties.

• Efficient protection functions require synchronized time, 

available either locally or globally. 21

• Timeliness of data availability, computation, and 

communication is needed in order to meet the system 

constraints to provide accurate state estimation and precise 

control automation.

• Ability is needed to specify and validate timing constraints.

• Grid operations use distributed equipment, which often 

includes time-aware capabilities based on the availability of 

timing as an infrastructural resource maintained by utilities.

Concerns related to the ability 

to design systems and 

components that are time 

aware and can acquire and use 

sufficiently accurate time 

signals.

• Architecture needs to support time awareness and 

synchronous time for protection schemes.

• Architecture needs to support the ability within 

applications to apply and validate timing constraints.

• Architecture needs to support sufficiently accurate 

time stamping ideally using designed-in and widely 

available timing infrastructures.

Timing Time-Interval 

and Latency

Specifying requirements for timing 

generally involves requirements for 

time-intervals between pairs of 

events. A time-interval is the 

duration between two instants read 

on the same timescale. CPS timing 

requirements are generally 

expressed as constraints on the time 

intervals (TI) between pairs of 

system significant events. These can 

be categorized in terms of bounded 

TIs or latency, deterministic TIs, 

and accurate TIs.

• As grid applications evolve, time-interval and latency 

requirements (including bounded latencies, and to prevent 

system destabilization) are becoming more stringent and 

complex. 

• Time-interval specificity is central to many new grid 

applications, from control systems to cybersecurity 

protections.

Concerns related to the ability 

to specify time interval and 

latency requirements for 

system events and 

communications.

• Architecture is needed to support multiple 

application-driven requirements for time-interval 

performance and latency.

Data Data Semantics Concerns related to the agreed and 

shared meaning(s) of data held 

within, generated by, and transiting 

a system.

• Efforts to combine data from multiple sources in the 

electric grid system face significant data interoperability 

challenges.40

• Data interoperability is a key need for grid modernization. 

• Data models and many data standards for smart grid 

devices support many different use cases; as a consequence, 

data semantics are not always seamless across systems.

Concerns related to the agreed 

and shared meaning(s) of data 

held within, generated by, and 

transiting a system.

• Standardization of communication interfaces and 

data harmonization is needed.

• As the ownership of grid devices for 

communication, sensing and actuation diversifies, 

additional effort will be needed to maintain data 

context (i.e., semantic interoperability) across devices 

and systems.
135

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Data Data Velocity Concerns related to the speed with 

which data operations are executed.

• The operational constraints of the electric grid demand that 

supply and demand be continuously balanced in real time, 

which creates significant requirements for data velocity to 

support real-time operations. 

• The increasing volumes of data inherent to the smart grid 

will challenge the ability to perform timely data operations. 

Concerns related to the speed 

with which data operations are 

executed, and the ability to 

process data within specified 

requirements.

• Architecture will need to accommodate different 

data processing speed requirements as a function of 

application and device type.

• Architecture will need to ensure data processing 

speed requirements for a given element are consistent 

with the employed control theory and system/device 

physical capabilities. 

Data Data Volume Concerns related to the volume or 

quantity of data associated with a 

CPS’ operation.

• The proliferation of smart sensors in the grid and other new 

data sources could overwhelm the data processing and 

analytics capabilities of the system.

• Grid operators may need to selectively manage datastreams 

to prioritize information that is most relevant to their 

operational goals.

• The dramatic growth in data availability from distributed 

sensing may create an archival data storage problem, in 

which so much data is stored that useful information may 

become obscured and access constrained. 

Concerns related to the ability 

to store the growing volume or 

quantity of data from grid 

devices and systems.

• Architecture support will be needed to meet growing 

data requirements for grid systems.

• Architecture elements will need to include the ability 

to address data capacity requirements from different 

types of devices and applications.

Data Identity Concerns related to the ability to 

accurately recognize entities 

(people, machines, and data) when 

interacting with or being leveraged 

by a CPS.

• Identity management is crucial to grid communications and 

operations.

• As ownership of grid assets diversifies, and as customers 

increasingly bring their own devices and expect to connect 

with any and all available communication systems, identity 

management schemes will have to be developed which allow 

for effective management of large numbers of diverse 

devices.

• Identity management of physical assets is critical to 

trustworthiness, cybersecurity, and grid operations.

Concerns related to the ability 

to uniquely identify devices in 

the system.

• Grid systems need the ability to identify and 

incorporate devices subject to diverse constraints and 

capabilities of distinct organizations, systems, and 

components.

• Highly distributed architectures will need to support 

device self-identification and registration.
136

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Data Operations on 

Data

Concerns related to the ability to 

create/read/update/delete system 

data and how the integrity of CPS 

data and behaviors may be affected.

• The quantity of data available to grid operators is 

increasing dramatically as sensing and communications 

capabilities are incorporated into all types of equipment. But 

the ability to use data is limited by data incompatibility, 

often driven by conflicts in format and structure. Ensuring 

appropriate data management, including data compatibility 

through uniform use of data models or other formatting, is 

critical to ensuring utilities can process, store, maintain and 

utilize the data according to their applications.

Concerns related to the ability 

to define data compatibility 

and data management 

requirements, including 

format, processing, storing and 

monitoring schemes.

• Architecture will need to support various data 

operations related to their applications.

Data Relationship 

between Data

Concerns related to how and why 

sets of data must, may, or may not 

be associated with each other and 

the value or harm that can be 

derived from those associations.

• Network convergence, such as referenced in natural 

gas/electric system harmonization efforts,11 will lead to 

complex and interconnected data streams, which will need to 

be managed in coordination to support cooperative 

operational management of integrated infrastructures. 

• Utilities and grid operators manage large quantities of 

sensor data generated by numerous equipment, to inform and 

improve grid operations efficiency, reliability and other 

attributes. By itself, or when associated with other data 

(commercial, residential), this information may add value or 

cause harm if not managed in an appropriate way. Internally, 

for example, data on power flows (state estimation) may 

reveal energy-market-relevant decisions and data that are to 

be protected. Externally, data about individual customers is 

typically protected from unauthorized disclosure within a 

state regulatory construct.

• Data from many sources impacts the accuracy of 

Distribution state estimation and other data analytics 

applications, and the relationship of disparate data sources 

will need to be evaluated to identify and enhance the value 

of such data to meet requirements of many applications. 

Concerns related to the

relationships of grid data and 

external data and the value or 

harm that can be derived from 

those associations.

• Integrated data management and analysis capabilities 

are needed effective coordinated operation of grid 

systems and other interacting systems, e.g. to support 

operational management of converged natural 

gas/electric power systems.55
137

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Boundaries Behavioral Concerns related to the ability to 

successfully operate a CPS in 

multiple application areas.

• Multiple value stacks for responsive grid support systems, 

e.g. energy storage systems, motivate maximal utilization of 

equipment and systems to meet multiple application 

objectives. These potentially overlapping applications are 

often subject to the requirements and expectations of 

multiple organizations, including those related to 

organizational boundaries.

• Operational siloes exist within utilities, such as between 

Informational Technology (IT) and Operational Technology 

(OT), and often lead to organizational boundaries which may 

increase the difficulty of managing CPS/IoT devices.89

Concerns related to successful 

operation at boundaries 

including geographic and 

system boundaries. 

• Architecture must support diverse operational and 

market uses for grid responsive systems, such as 

energy storage systems.

• Architecture practices need to consider differing IT 

and OT perspectives.

Boundaries Networkability Concerns related to the ease and 

reliability with which a CPS can be 

incorporated within a (new or 

existing) network of other systems.

• Increasing growth of edge-connected devices and systems, 

e.g. DERs, is requiring development of network capabilities 

to manage and readily accommodate the incorporation of 

such devices. Positive attributes, such as ease of connection 

and reliability of edge devices, are accompanied by the need 

to reassess existing capabilities and processes, including 

protection schemes6 to prevent negative impacts such as 

outages that may result from unanticipated two-way power 

flows. 

Ease and reliability of 

incorporation of newer 

technology and updated 

systems models at various grid 

levels while maintaining the 

integrity of the grid network.

• With increased networkability and ease of 

incorporation of new devices and systems into the 

grid, advanced control systems are needed to manage 

such systems and protect grid systems from 

unintended consequences.
138

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Boundaries Responsibility Concerns related to the ability to 

identify the entity or entities 

authorized to control the operation 

of a CPS.

• Business model changes for utilities, including those driven 

by the availability of significant distributed generation, may 

include creation of new Distribution System Operators with 

stakeholder expectations that income will result from 

distribution services instead of the volumetric sale of 

electricity. 17 These new organizations and structures will 

result in new organizational responsibilities, which will need 

to be understood, communicated and agreed with applicable 

system participants.

• Additional coordination will be needed between microgrids 

and the larger grid and between microgrids and other 

microgrids.31

• Greater understanding and coordinated management of 

responsibilities between Distribution System Operators 

(DSO) and RTOs/ISOs will be needed. 

• Utility resource planning and accommodation of increasing 

DERs will need to incorporate recognitions of boundary 

interfaces and associated responsibilities of authorized grid 

operators.

• Customers may have opportunities and responsibilities 

based on their use of grid-responsive equipment (e.g. 

demand response) with the ability to vary power 

consumption to meet multiple objectives.

Identification and 

determination of the 

responsibilities of authorized 

grid organizations and 

participants, including with 

respect to ownership and 

control of diverse grid 

components.

• Transmission/distribution coordination via 

Distribution System Operator models is needed.71

• Circuit structure, protection and control structures 

are needed for multiple cooperating microgrids.83

• Architectures for multi-scale (e.g. single building 

versus multiple circuits) coordination of microgrid 

networks needed.84

• Architecture needed for CCAs and aggregated 

community resources.85

• Architecture support is needed for segmentable and 

coordinated grid sub-systems and for coordination of 

responsibilities to facilitate agile re-segmentation and 

cooperation at different microgrid scales (e.g. single 

building versus multiple circuits).86

• Under one proposed framework, the DSO would 

serve as a system optimizer on the local level, calling 

on least-cost resources to meet distribution system 

goals. The least-cost resources could be provided 

directly by customers or, more likely, by third-party 

aggregators.87

• Standardization of interfaces between utility 

resource planning tools and DERs would increase 

effectiveness of DERs. 

• Consumers would benefit from development of 

clearly defined guidelines for customer participation, 

costs, benefits and responsibilities related to the 

integration of grid-responsive devices and systems.
139

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Composition Adaptability Concerns related to the ability of the 

CPS to achieve an intended purpose 

in the face of changing external 

conditions such as the need to 

upgrade or otherwise reconfigure a 

CPS to meet new conditions, needs, 

or objectives.

• Grid components are supplied by various vendors. It can be 

challenging for components from different vendors to 

communicate with one another in the power system network, 

and to be reconfigured as needed to meet new objectives.

• Grid control algorithms need to be much more flexible and 

adaptable in order to consider varying market economics, 

efficient energy usage, and managing reliability with a 

diversity of resources, such as storage and demand response, 

and in areas with high penetrations of wind and solar 

generation.

Ability to update, adapt or 

reconfigure grid technology to 

meet power system needs.

• Interoperability standards for grid components 

continue to be needed to support composition and 

integration of components into systems that are 

adaptable and able to meet system requirements.

• Preparedness for future grid technology including 

attention to its adaptability and reconfigurability to 

meet new objectives is needed.

• Architecture is needed for integration of large-scale 

energy storage distribution connected resources and 

grid operations.58

• Balancing and stabilization of grids with wide area 

bulk wind and solar resources is needed.59

• Distributed intelligence computations and 

communication network structures are needed to 

support distributed analytics, and control.69

• Coordination, communication, and sensing 

structures that facilitate use of Demand Response for 

grid resilience purposes are needed.67

• New hybrid central/distributed control structures are 

needed for distribution control to facilitate functional 

flexibility and grid resilience.70

Composition Complexity Concerns related to our 

understanding of the behavior of 

CPS due to the richness and 

heterogeneity of interactions among 

its components, such as existence of 

legacy components and the variety 

of interfaces.

• Grid complexity is such that it is unlikely any one person 

or organization can understand and/or plan for the entirety of 

it.15

Concerns relating to 

complexity in grid 

functionality.

• Movement of control/management/optimization to 

lower levels will help to manage complexity. 

• Grid partitioning, coordination and communication 

are means to adapt to grid complexity and stresses.61 
140

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Composition Constructivity Concerns related to the ability to 

combine CPS modular components 

(hardware, software, and data) to 

satisfy user requirements.

• Integrating hardware, software and data components in 

complex systems is a difficult endeavor, and particularly so 

in grid systems with their legacy systems and operational 

requirements. For example, replacing an Outage 

Management System (OMS) and Distribution Management 

System (DMS) with an Advanced DMS (ADMS) poses 

complex deployment issues, including how to replace both 

the OMS and DMS at the same time, optimize data 

alignment/transfer, maintain consistency in calculating 

reliability metrics, and complete operator training. 

Integration of power system 

components of various types 

and configurations.

• Architectures need to be developed with interface 

design and considerations to support modular 

composition of components, including the ability to 

address use of the same data by multiple applications, 

varying data rates, and standardized data definitions, 

e.g. CIM.

Composition Discoverability Concerns related to the ease and 

reliability with which a CPS 

component can be observed and 

understood (for purposes of 

leveraging the component’s 

functionality) by an entity (human, 

machines). Concerns related to the 

ease and reliability with which a 

CPS component’s functions can be 

ascertained (for purposes of 

leveraging that functionality) by an 

entity (human, machines).

• The grid has increasing needs for system observability and 

discoverability, including with respect to communication 

(data flow) and information handling.

• System operators want greater visibility into the operation 

and status of DER assets and other assets that may be owned 

or controlled by other parties. 

Concerns related to the 

observability of power systems 

components needed to leverage 

component data.

• Automated discoverability of edge-connected 

devices and sensors and their performance 

characteristics, communications and data models is a 

need to enable improved visibility, integration, and 

device management to support grid operations.

• Fault tolerant communication structures are needed 

to enable reliable distributed intelligence.62

• Architecture support is needed to enable 

discoverability and visibility of DERs and to support 

centralized and decentralized control of DERs.
141

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Lifecycle Deployability Concerns related to the ease and 

reliability with which a CPS can be 

brought into productive use.

• The mission-critical nature of the grid limits the ability to 

test new systems, as outages are unacceptable. Thus models, 

simulations, and testable versions of the grid are needed to 

test new systems, algorithms, markets capabilities and 

understand and mitigate factors affecting their deployability 

on the functioning grid. 

• Utility-scale wind and solar power often generated in 

sparsely populated areas with little grid infrastructure. Hence 

long-distance transmission lines must be built to move 

wind/solar generation to areas where power is needed, which 

may lead to additional concerns such as initial deployability 

of these assets.

• Reduction of system inertia, including that associated with 

inverter-based generation in some cases, may require 

additional control actions by regulating tap changers and 

capacitors54 and which may affect the perceived 

deployability of these assets.

Concerns related to the 

implementation of grid 

technology to meet power 

system needs.

• Architectural support is needed for new or updated 

models and simulation of the electric grid including 

DERs.

• Bulk energy systems require closed loop secondary 

protection and System Integrity Protection Schemes 

(SIPS).56

Sensors and communications are needed for 

transmission state determination and situational 

awareness.57

• Structures are needed for integration of inertia 

augmentation methods, devices, and systems.60

Lifecycle Disposability Concerns related to the impacts that 

may occur when the CPS is taken 

physically out of service.

• There is an ongoing need to plan for retirement and 

eventual disposal/deconstruction of large power plants at the 

end of their lifecycle. 

• Planning is needed to support identification and disposal of 

faulty grid equipment, and to enable recycling of out-ofservice grid components that may be of use elsewhere.

Concerns related to the 

disposal of obsolete, aged, or 

damaged physical grid 

components. 

• Architecture is needed to support environmentalfriendly recycling practices.

• Improved quality checks are needed to minimize 

faulty equipment.

Architecture support is needed to enable use of 

recycled grid components elsewhere in the grid.
142

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Lifecycle Engineerability Concerns related to the ease and 

reliability with which a CPS design 

concept can successfully be realized 

via a structured engineering process.

• There are multiple systems engineering approaches and 

methodologies available to support architecture development 

and a variety of structured engineering processes. Within 

systems engineering processes applied at the grid component 

level, the broader perspective of the grid at-scale is 

beneficial to identify and address engineerability issues. 

Included in this approach is research and development 

needed to better understand and improve the behavior and 

performance of new innovative products, to ensure that these 

concepts can be realized and deployed at scale and are likely 

to function in grid environments. 

• Microgrid engineering issues have been studied, but 

architecture coordination issues remain.32

• Time lags may exist in translating new concepts into 

standards and implementation, which should be identified 

and mitigated as needed, e.g., through initiating testing and 

certification development based on earlier working versions 

of a standard.

Ability to develop theoretical 

concepts into applicable grid 

technology.

• Common structured engineering processes should 

be identified and used broadly across the electric 

sector to help improve engineerability and integration 

of new components and systems into the operational 

power grid. 

• Microgrid architecture models are needed.

Lifecycle Maintainability Concerns related to the ease and 

reliability with which the CPS can 

be kept in working order.

• The aging grid means that many assets are reaching or have 

already surpassed their designed lifetimes, and maintenance 

of these assets and systems is a growing concern for keeping 

the system operational.

• The introduction of smart devices in the grid are changing 

maintenance processes and procedures. For example, the 

different classes of devices require different monitoring 

schemes (e.g. traditional grid devices may require visual 

inspection while smart devices could be monitored remotely).

• Smart devices and systems may enable predictive 

maintenance to replace some preventive and reactive 

maintenance regimes.

Concerns related to the ease 

and reliability with which the 

grid and its assets can be kept 

in working order. 

• Architecture needs to support different maintenance 

intervals for different classes of devices.

• Architecture needs to accommodate a variety of 

emerging maintenance regimes, including predictive 

maintenance.
143

Aspect Concern Description Grid Context for CPS Concern Grid CPS Concern 

Description

Architecture Significance

Lifecycle Operability Concerns related to the operation of 

the CPS when deployed.

• Electric system components are often designed with long 

lifetimes that may exceed 30 years90 and must maintain 

operability over this time period.

• Like other critical infrastructures, the electric grid is aging, 

and must be kept operational through upgrade or 

replacement by new systems. These upgrade or replacement 

events represent opportunities to introduce additional system 

advances such as incorporating an IoT-based infrastructure. 

• The increasing complexity of grid controls requires a more 

skilled workforce to maintain operability of grid systems. 

• Firmware upgrades in existing devices provide opportunity 

to deploy new features such as the ability of advanced 

inverters to control voltage and frequency.

Concerns related to 

continuous, effective operation 

of grid components.

• Architecture needs to accommodate both new and 

legacy devices.

• Architecture needs to support rollout of new 

Internet connectivity when systems are added or 

replaced.

• Architecture needs to support integrated 

training/operations simulation.

• Architecture needs to support field upgrades of 

device firmware.

Lifecycle Procureability Concerns related to the ease and 

reliability with which a CPS can be 

obtained.

• Historically, performance requirements for grid assets or 

devices have been locally determined, and driven by 

interfaces with legacy systems or capabilities. This situation 

often leads to procurement issues as equipment often 

requires customized configurations to match capabilities 

with the legacy requirements. Grid operators are moving 

towards open-source standards-based device requirements, 

which allows for easier specification in the procurement 

process. 

• Common reference procurement language could be useful 

for purchasers to specify and procure devices that minimize 

integration overhead.

Concerns related to the ability 

to specify performance and 

communication requirements 

for a device.

• Architecture needs to support standardized device 

requirements to support procureability.

• Common reference language for procurement 

documentation and examples of standards-based 

performance requirements should be developed

Lifecycle Producibility Concerns related to the ease and 

reliability with which a CPS design 

can be successfully manufactured.

• The grid itself is not manufactured, but instead it results 

as the product of many individual design, procurement, and 

installation activities. 

• Absent a comprehensive master design, devices 

manufactured to meet open standards improves the 

likelihood that grid components will be manufactured to 

conform with grid design requirements.

Concerns around the ability to 

translate grid designs into 

successful products and 

installations.

• Architecture needs to support standardized device 

requirements to support producibility.

1
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Table 14 References

1 Key Influences in GMLC 1.2.1 Grid Architecture: Architecture Track Description, DRAFT 

Version 0.1 25 May 2017.

2 Bakke, Gethchen. Introduction in: The Grid: the Fraying Wires between Americans and our 

Energy Future, New York: Bloomsbury, USA, 2016; pages xi-xii

3 Advanced Bulk Energy Systems Key Influences in GMLC 1.2.1 Grid Architecture: 

Architecture Track Description, DRAFT Version 0.1 25 May 2017. 

4 Bakke, Gethchen. Introduction in: The Grid: the Fraying Wires between Americans and our 

Energy Future, New York: Bloomsbury, USA, 2016; pages xxvii-xxviii

5 Bakke, Gethchen. Introduction in: The Grid: the Fraying Wires between Americans and our 

Energy Future, New York: Bloomsbury, USA, 2016; page xv

6 Kay Stefferud, Jens Schoene, Vadim Zheglov; EnerNex LLC 2015; Jan Kleissl, UCSD. 

Utility Scale Solar Forecasting, Analysis, and Modeling Final Report. California Energy 

Commission. Publication number: CEC-500-2010-060.

7 Bakke, Gethchen. Introduction in: The Grid: the Fraying Wires between Americans and our 

Energy Future, New York: Bloomsbury, USA, 2016; page xvii

8 Advanced Bulk Energy Systems Key Influences in GMLC 1.2.1 Grid Architecture: 

Architecture Track Description, DRAFT Version 0.1 25 May 2017.

9 https://www.pv-magazine.com/2017/07/19/hawaii-regulators-approve-hecos-100-renewableenergy-plan/

10 Bakke, Gethchen. Introduction in: The Grid: the Fraying Wires between Americans and our 

Energy Future, New York: Bloomsbury, USA, 2016; page xxii 

11 Advanced Bulk Energy Systems Key Influences in GMLC 1.2.1 Grid Architecture: 

Architecture Track Description, DRAFT Version 0.1 25 May 2017.

12 Bakke, Gethchen. Introduction in: The Grid: the Fraying Wires between Americans and our 

Energy Future, New York: Bloomsbury, USA, 2016; page xxii

13 Bakke, Gethchen. Introduction in: The Grid: the Fraying Wires between Americans and our 

Energy Future, New York: Bloomsbury, USA, 2016; page xxiv

14 Bakke, Gethchen. Introduction in: The Grid: the Fraying Wires between Americans and our 

Energy Future, New York: Bloomsbury, USA, 2016; page xxv

15 Bakke, Gethchen. Introduction in: The Grid: the Fraying Wires between Americans and our 

Energy Future, New York: Bloomsbury, USA, 2016; page xxvi

16 High Resilience Grid Key Influences in GMLC 1.2.1 Grid Architecture: Architecture Track 

Description, DRAFT Version 0.1 25 May 2017.

17 http://americaspowerplan.com/2014/09/trending-topics-in-electricity-today-the-distributionsystem-operator/

18 Bakke, Gethchen. Introduction in: The Grid: the Fraying Wires between Americans and our 

Energy Future, New York: Bloomsbury, USA, 2016; page xxx

20 Framework for Cyber-Physical Systems: Volume 3, Timing Annex, page 46

21-23Framework for Cyber-Physical Systems: Volume 3, Timing Annex, page 48

24-25Framework for Cyber-Physical Systems: Volume 3, Timing Annex, page 49

26 Bakke, Gethchen. Introduction in: The Grid: the Fraying Wires between Americans and our 

Energy Future, New York: Bloomsbury, USA, 2016; page xiii

27 Bakke, Gethchen. Introduction in: The Grid: the Fraying Wires between Americans and our 

Energy Future, New York: Bloomsbury, USA, 2016; pages xiv-xv

28-30High DER High Automation Key Influences in GMLC 1.2.1 Grid Architecture: Architecture 

Track Description, DRAFT Version 0.1 25 May 2017.

31-32Microgrid Key Influences in GMLC 1.2.1 Grid Architecture: Architecture Track Description, 

DRAFT Version 0.1 25 May 2017.
145

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33-38Architecture Key Influences in GMLC 1.2.1 Grid Architecture: Architecture Track 

Description, DRAFT Version 0.1 25 May 2017.

39 Framework for Cyber-Physical Systems, Release 1.0, May 2016

40 Framework for Cyber-Physical Systems, Release 1.0, May 2016, B.5.2.1.1

41 Moving Toward Value in Utility Compensation, Part 2 - Regulatory Alternatives, 

http://americaspowerplan.com/wp-content/uploads/2016/06/2016_Aas-OBoyle_RegAlternatives.pdf

42-43High Resilience Grid Key Influences in GMLC 1.2.1 Grid Architecture: Architecture Track 

Description, DRAFT Version 0.1 25 May 2017. 

44-52Urban Converged Network Architecture Strategy in GMLC 1.2.1 Grid Architecture: 

Architecture Track Description, DRAFT Version 0.1 25 May 2017.

53 Climate Change Indicators: Weather and Climate, United States EPA website, 

https://www.epa.gov/climate-indicators/weather-climate

54 Kay Stefferud, Jens Schoene, Vadim Zheglov; EnerNex LLC 2015; Jan Kleissl, UCSD. 

Utility Scale Solar Forecasting, Analysis, and Modeling Final Report. California Energy 

Commission. Publication number: CEC-500-2010-060.

55-61Advanced Bulk Energy Systems Architecture Strategy in GMLC 1.2.1 Grid Architecture: 

Architecture Track Description, DRAFT Version 0.1 25 May 2017.

62-69High Resilient Grid Architecture Strategy in GMLC 1.2.1 Grid Architecture: Architecture 

Track Description, DRAFT Version 0.1 25 May 2017.

70- 81 High DER Grid Architecture Strategy in GMLC 1.2.1 Grid Architecture: Architecture Track 

Description, DRAFT Version 0.1 25 May 2017.

82- 86 Microgrid Architecture Strategy in GMLC 1.2.1 Grid Architecture: Architecture Track 

Description, DRAFT Version 0.1 25 May 2017.

87 America’s Power Plan, Trending Topics in Electricity Today, the Distribution System 

Operator, http://americaspowerplan.com/2014/09/trending-topics-in-electricity-today-thedistribution-system-operator/

88 Smith, J. Charles, “A Major Player: Renewables are Now Mainstream,” IEEE Power & 

Energy Magazine, 18 October 2017:16. Print. Also Lazard Levelized Cost of Energy 

Analysis─Version 10.0, pp 4-5

89 Derek R. Harp, Bengt Gregory-Brown, IT/OT Convergence: Bridging the Divide, pages 3-5, 

https://ics.sans.org/media/IT-OT-Convergence-NexDefense-Whitepaper.pdf

90 UtiltyDIVE, http://www.utilitydive.com/news/making-the-case-for-grid-investment-6-

insights-from-the-white-houses-new/160426/

91 Hawaiian Public Utilities Commission, Order Number 34924, page 81, proposed Smart 

Export schedule, October 20, 2017

92 NIST Special Publication 1800-7, Situational Awareness for Electric Utilities, Draft, 

February, 2017
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1 Appendix C – Inverter and DER Functions

2

3 This appendix lists new DER functions which have been identified over the last few years. 

4 Some of these are becoming mandatory through California Rule 21 [153] and IEEE 1547-

5 2018 [154]. Others are focused on the market-based services which the DER system could 

6 provide.

7

8 Table 15 – Inverter and DER functions: mandatory, autonomous, and market-based

# DER Functions Description and Key Parameters

Mandatory DER Functions (Regulatory Requirements from IEEE 1547 and California’s Rule 

21)

1. Disconnect/Connect Function

Disconnect or connect the DER from 

the grid at its electrical connection 

point (ECP)

The disconnect command initiates the galvanic separation (usually 

via switches or breakers) of the DER at its ECP or at the PCC. There 

may be a time delay between receiving the command and the actual 

disconnect

The connect command initiates or allows the reconnection of the 

DER at its ECP or at the PCC. A permission to reconnect may also 

be issued.

2. Cease to Energize and Return to 

Service

The DER ceases all active power 

output

Allow active power output at the PCC

“Cease to energize” is a different function from disconnect/connect. 

IEEE 1547 states the DER shall not export active power during 

steady-state or transient conditions, and that reactive power exchange 

(absorb or supply) shall be less than 10% of nameplate DER rating 

and shall exclusively result from passive devices. There may be a 

time delay between receiving the command and the actual cease to 

energize.

“Return to service” allows current flow at the PCC. A permission to 

return to service may also be issued.

3. High/Low Voltage Ride-Through 

Mode

The DER rides through temporary 

fluctuations in voltage

The DER follows the utility-specified voltage ride-through 

parameters to avoid tripping off unnecessarily. The function would 

block tripping within the fault ride-through zones.

Although normally enabled by default, this ride-through mode may 

be updated, enabled, and disabled.

4. High/Low Frequency Ride-Through 

Mode

The DER rides through temporary 

fluctuations in frequency

The DER follows the utility-specified frequency ride-through 

parameters to avoid tripping off unnecessarily. The function would 

block tripping within the fault ride-through zones. Although 

normally enabled by default, this ride-through mode may be update, 

enabled, and disabled.

5. Dynamic Reactive Current Support 

Mode

The DER reacts against rapid voltage 

changes (spikes and sags) to provide 

dynamic system stabilization

dV/dt

The DER provides dynamic reactive current support in response to 

voltage spikes and sags, similar to acting as inertia against rapid 

changes. This mode may be focused on emergency situations or may 

be used during normal operations.

When the dynamic reactive current support mode is enabled, the 

DER monitors the voltage at the referenced ECP and responds based

on the parameters.
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# DER Functions Description and Key Parameters

6. Frequency-Watt Mode 

The DER responds to large frequency 

excursions during abnormal events at 

a referenced ECP by changing its 

production or consumption rate 

The DER is provided with frequency-watt curves that define the 

changes in its watt output based on frequencies around the nominal 

frequency during abnormal events.

When the emergency frequency-watt mode is enabled, the DER 

monitors the frequency and adjusts its production or consumption 

rate to follow the specified emergency frequency-watt curve 

parameters. 

7. Volt-Watt Mode

The DER responds to changes in the 

voltage at the referenced ECP by 

changing its production or 

consumption rate 

The DER is provided with voltage-watt curves that define the 

changes in its watt output based on voltage deviations from nominal, 

as a means for countering those voltage deviations.

When the volt-watt mode is enabled, the DER receives the voltage 

measurement from a meter (or other source) at the referenced ECP. 

The DER adjusts its production or consumption rate to follow the 

specified volt-watt curve parameters. 

8. Fixed (Constant) Power Factor 

Mode

The DER power factor is set to a fixed 

value.

The DER power factor is set to the specified power factor. A leading 

power factor is positive and a lagging power factor is negative, as 

defined by the IEEE or IEC sign conventions. 

9. Fixed (Constant) Reactive Power 

Mode

The DER is requested to provide a 

fixed amount of reactive power

The DER is requested to provide a fixed amount of reactive power

10. Volt-Var Control Mode

The DER responds to changes in 

voltage at the referenced ECP by 

supplying or absorbing vats in order to 

maintain the desired voltage level

The DER is provided with curves that define the vars for voltage 

levels.

When the volt-var mode is enabled, the DER receives the voltage 

measurements from a meter (or other source) at the referenced ECP. 

The DER responds by supplying or absorbing vars according to the 

specified volt-var curve in order to maintain the desired voltage 

level. 

11. Watt-Var Mode 

The DER responds to changes in 

power at the referenced ECP by 

changing its vars

The DER is provided with watt-var curves that define the changes in 

its vars based changes of power.

When the watt-var mode is enabled, the DER modifies its vars

setting in response to the power level at the referenced ECP. 

12. Watt-PF Mode

The DER responds to changes in 

power at the referenced ECP by 

changing its power factor

The DER is provided with watt-PF curves that define the changes in 

its power factor based changes of power.

When the watt-PF mode is enabled, the DER modifies its PF setting 

in response to the power level at the referenced ECP. 

13. Set Active Power Mode

Set the DER to generate or consume 

energy as a percentage of maximum 

capability

The DER is set to a percentage of maximum generation or 

consumption rate. A positive value indicates generation, negative 

means consumption.
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# DER Functions Description and Key Parameters

14. Limit Active Power Production or 

Consumption Mode

Limits the production and/or 

consumption level of the DER based 

on the referenced ECP

The production and/or consumption of the DER is limited at the 

referenced ECP, indicated as absolute watts values. Separate 

parameters are provided for production or consumption limits to 

permit these to be different. 

15. Low Frequency-Watt Emergency 

Mode for demand side management 

(fast load shedding)

Enable automatic disconnection of a specified proportion of their 

demand (in stages) under low frequency conditions in a given time 

frame. 

16. Low Voltage-Watt Emergency 

Mode for demand side management

Provide capabilities to enable automatic or manual load tap changer 

blocking and automatic disconnection under low voltage conditions.

17. Monitoring Function

The DER provides nameplate, 

configuration, status, measurements, 

and other requested data

The DER provides status, measurements, alarms, logs, and other data 

as authorized and requested by users. Examples include connect 

status, updated capacities, real and reactive power 

output/consumption, state of charge, voltage, and other 

measurements. Also of interest are forecast statuses and expected 

measurements.

18. Scheduling of Power Settings and 

Modes

The DER follows the schedule which consists of a time offset 

(specified as a number of seconds) from the start of the schedule and 

is associated with:

• a power system setting 

• the enabling/disabling of a function

• a price signal

Market-Based DER Functions

19. Peak Power Limiting Mode

The DER limits the load at the 

referenced ECP after it exceeds a 

threshold target power level

The active power output of the DER limits the load at the referenced 

ECP if it starts to exceed a target power level, thus limiting import 

power. The production output is a percentage of the excess load over 

the target power level. The target power level is specified in absolute 

watts.

20. Load Following Mode

The DER counteracts the load by a 

percentage at the referenced ECP, 

after it starts to exceed a threshold 

target power level

The active power output of the DER follows and counteracts the load 

at the referenced ECP if it starts to exceed a target power level, thus 

resulting in a flat power profile. The production output is a 

percentage of the excess load over the target power level. The target 

power level is specified in absolute watts.

21. Generation Following Mode

The consumption and/or production of 

the DER counteracts generation power 

at the referenced ECP.

The consumption and/or production of the DER follows and 

counteracts the generation measured at the referenced ECP if it starts 

to exceed a target power level. The consumption and/or production 

output is a percentage of the excess generation watts over the target 

power level. The target power level is specified in absolute watts.
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# DER Functions Description and Key Parameters

22. Dynamic Active Power Smoothing 

Mode

The DER produces or absorbs active 

power in order to smooth the changes 

in the power level at the referenced 

ECP.

Rate of change of power – dW/dt

The DER follows the specified smoothing gradient which is a signed 

quantity that establishes the ratio of smoothing active power to the 

real-time delta-watts of the load or generation at the referenced ECP.

When the power smoothing mode is enabled, the DER receives the 

watt measurements from a meter (or other source) at the referenced 

ECP. New data points are provided multiple times per second.

23. Frequency-Watt Primary Control 

mode

The DER changes its watt output or 

input to provide frequency support to 

maintain frequency within normal 

limits

The DER changes its watt output or input based on parameters or 

curves, to provide primary frequency control with the purpose of 

maintaining frequency within the normal frequency limits

24. Automatic Generation Control 

(AGC) Mode

The DER responds to raise and lower 

power level requests to provide 

frequency regulation support

When AGC mode is enabled, the DER responds to signals to 

increase or decrease the rate of consumption or production every 4 to 

10 seconds, with the purpose of managing frequency. 

25. Operating Reserve (Spinning 

Reserve) mode

The DER provides operating reserve

The DER can provide reserve power available within about 10 

minutes

26. Dynamic Frequency-Watt Mode

The DER responds to the rate of 

change of frequency (ROCOF) by 

changing its watt output or input to 

minimize spikes and sags

The DER responds to the rate of change of frequency (ROCOF) by 

changing its watt output or input to minimize spikes and sags

27. Coordinated Charge/Discharge 

Management Mode

The DER determines when and how 

fast to charge or discharge so long as 

it meets its target state of charge level 

obligation by the specified time (focus 

is on Electric Vehicle consumption)

The DER is provided with a target state of charge and a time by 

which that SOC is to be reached. This allows the DER to determine 

when to charge or discharge based on price.

The DER takes into account not only the duration at maximum 

consumption / production rate, but also other factors, such as that at 

high SOC the maximum consumption rate may not be able to be 

sustained, and vice versa, at low SOC, the maximum discharge rate 

may not be able to be sustained

28. Frequency-Watt Smoothing Mode

The DER responds to changes in 

frequency at the referenced ECP by 

changing its consumption or 

production rate based on frequency 

deviations from nominal, as a means 

for countering those frequency 

deviations

df/dt

The DER is provided with frequency-watt curves that define the 

changes in its watt output based on frequency deviations from 

nominal, as a means for countering those frequency deviations and 

smoothing the frequency.

When the frequency-watt mode is enabled, the DER monitors the 

frequency and adjusts its production or consumption rate to follow 

the specified frequency-watt curve parameters. New data points are 

provided multiple times per second. 
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# DER Functions Description and Key Parameters

29. Power Factor (PF) Limiting 

(Correcting) Mode

The DER supplies or absorbs VArs to 

hold the power factor at the referenced 

ECP within the PF limit

When the PF limiting (correcting) mode is enabled, the DER is 

provided with the target PF. The DER supplies or absorbs VArs in 

order to maintain the PF at the referenced ECP within the limits of 

the target PF.

30. Delta Power Control Function 

Decrease active power output to 

ensure there remains spinning reserve 

amount that was bid into the market

Decrease active power output to ensure there remains spinning 

reserve amount that was bid into the market

31. Power Rate Control

The power is limited by the maximum 

ramp rate.

Manage active power ramp time, when the active power should be at 

the required power level by the end of the ramp time. It may reach 

the required power level earlier, but not later.

32. Dynamic Volt-Watt Function

Dynamically absorb or produce 

additional watts in proportion to the 

instantaneous difference from a 

moving average of the measured 

voltage

Dynamically absorb or produce additional watts in proportion to the 

instantaneous difference from a moving average of the measured 

voltage. This function utilizes the same basic concepts and settings as 

the Dynamic Reactive Current function but uses active power as an 

output rather than reactive current.

Non-Operational Requirements

33. Collect and Provide Historical 

Information

Collect and provide detailed 

measurement and performance data 

which may be valuable to record in an 

operational historian

Collect and provide detailed measurement and performance data,

which may be used to assess the real-time responses to power system 

events, control commands, and autonomous functions. This data 

could also be used to determine actual capabilities, impacts, 

compliance, and other characteristics of DER systems.

Capabilities Not Yet Defined by Regulations, EPRI, or IEC 61850

34. Microgrid Separation Control 

(Intentional Islanding)

Process for normal separation, 

emergency separation, and 

reconnection of microgrids

Process for normal separation, emergency separation, and 

reconnection of microgrids. These microgrids could be individual 

facilities or could be multiple facilities using electric grid equipment 

between these facilities.

35. Provide Black Start Capability

Support the reestablishment of power 

after an outage

Ability to start without grid power, and the ability to add significant 

load in segmented groups.

36. Provide Backup Power (Often 

implemented, but not standardized)

Ability to provide power to local loads 

when not connected to the grid

Ability to provide power to local loads behind a PCC when the 

facility is not connected to the grid, either during an outage or due to 

intentional or unintentional islanding.

1
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1 Appendix D – The Core Set of Electric Industry Roles

2

3 The Smart Grid Conceptual Model is useful for describing the core roles across the electricity 

4 sector and examining their relationship to system economics.

5

6 Generation Including DER. Generators provide value to the industry through the 

7 conversion of primary energy to electricity. The source of this conversion most commonly is 

8 nuclear fuel, carbon-based fuel (e.g., coal, natural gas, oil), moving or stored water, or 

9 renewable (e.g., solar, wind, geothermal). Depending on the state, generators may be owned 

10 by the utility or a third party. Nevertheless, generators are typically dispatched either based 

11 upon the incremental production costs through bidding into the market. In markets, 

12 generators are compensated at the lowest marginal cost of the next available unit of 

13 generation. 

14

15 Generators are compensated, primarily, for the units of energy (MWh) they produce; 

16 however, they may also receive compensation for “ancillary services,” which include 

17 spinning reserve, frequency control, and other “products” required for stability of the 

18 transmission grid. Production costs for generating units consists of fuel cost, non-fuel 

19 operations and maintenance costs, and the “carrying cost” of the generation assets.

20

21 Currently, some types of DER may be dispatched, such as demand response. In most cases, 

22 DER does not currently receive compensation for ancillary services. However, the Federal 

23 Energy Regulatory Commission has been lowering barriers to entry for multiple types of 

24 DER to participate directly in wholesale markets, and directing RTOs to develop models and 

25 tariffs to allow for DER to participate and be compensated for its services[168, 169].

26

27 Transmission. Entities within the Transmission domain provide value by delivering bulk 

28 generation at high voltages over long distances from its source to either large customers that 

29 can utilize these high voltages, or to distribution networks, where voltage levels are lowered 

30 and electricity is delivered to end-use customers. With the exception of the ERCOT region of 

31 Texas, all transmission providers in the continental United States are regulated by FERC, 

32 which regulates the tariffs that serve as the basis for their compensation [170].

33

34 Distribution. Distribution companies add value by delivering generated electricity from 

35 transmission networks or DERs to end-use customers. Entities within the distribution domain 

36 are monopolies -- typically investor-owned utilities, cooperatives, or public power entities 

37 whose rates are determined by regulators or other governing bodies. In most jurisdictions, the 

38 cost of the energy being delivered is a pass-through cost to the customer, with separate, un39 bundled tariffs/fees for the provided delivery services. However, in other jurisdictions, the 

40 costs of generation, transmission, and distribution are bundled into a single customer rate.

41

42 Markets. Wholesale electricity markets in the US are managed by RTOs or ISOs. They add 

43 value through managing bulk power flows, ensuring reliability of the transmission grid, and 

44 through transmission planning across its footprint. These FERC-regulated entities are 

45 compensated for their market management and settlement services via volume-based tariffs. 

46 Broad distribution-level markets do not currently exist within the industry in the United 
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1 States; however, recent regulatory activity in California and New York signal the creation of 

2 distribution-level market platforms in those states.

3

4 Electric Service Providers. Electric Service Providers add value as interfaces between 

5 customers and either the distribution or markets domain. A common value-added role that an 

6 electric service provider might play is in aggregating the load and/or demand response 

7 capability of smaller customers that do not have feasible access to an energy market. In 

8 deregulated markets, Electric Service Providers compete to sell electricity to end use 

9 customers, with the latitude to structure how energy is priced and what, if any, services are 

10 bundled in with the energy. Energy Service Providers also help commercial and industrial 

11 customers manage their usage against relevant customer rate designs – typically to manage 

12 peak load and related peak demand charges. Non-utility electric vehicle charging networks 

13 represent another emerging role for Electric Service Providers.

14

15 Customer. Many electricity customers have evolved to be more active in the management of 

16 their energy consumption. The majority of US electricity customers now have smart meters 

17 installed at their premises. With the customer web portals that utilities often make available 

18 with smart meter installations, customers have access to energy usage information and, often, 

19 greater insight and awareness into their energy usage and ways to manage it. Residential and 

20 commercial customers are increasingly opting to reduce their energy costs through 

21 investments in energy efficiency, rooftop solar and energy storage. With rooftop solar 

22 achieving cost parity with utility-delivered energy in many states and the declining cost of 

23 energy storage, this trend can be expected to continue. Commercial and industrial customers 

24 in deregulated energy states have utilized retail electric service providers to lower their cost 

25 of energy. Large commercial customers, particularly those with large buildings, are 

26 increasingly installing and utilizing building energy management systems to help control 

27 their energy costs.
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1 Appendix E – Cost Recovery, Rate Design, and Regulation

2

3 Ratemaking is a complex activity that incorporates a number of economic and societal 

4 considerations. Because electricity distribution is regulated at the state and local level, 

5 executed by utilities with differing ownership structures and business models, and involves 

6 balancing of inherently local considerations such as the impact grid design and weather have 

7 on the ability to meet customer demand, the electricity rates for each utility will be 

8 necessarily unique. Despite this complexity, the elements of cost recovery, rate design, and 

9 oversight for natural monopolies are common to the economics of all electrical distribution 

10 utilities.

11

12 Cost recovery: Utilities recover their costs via customer bills. For utilities that are regulated 

13 by a state utility commission, a utility will submit an application for recovery of all costs plus 

14 profit for approval by the utility commission. The utility commission will then approve an 

15 authorized amount of revenue to be collected (revenue requirement) via customer bills. The 

16 approved revenue requirement is then allocated across customer classes based on a 

17 determination of which class is responsible for which portion of the costs. The result of this 

18 analysis is a determination of billing components, e.g., fixed charges, volumetric charges, 

19 and demand charges (where applicable). 

20

21 In some states, mostly those with retail competition, these charges are unbundled into 

22 specific generation, transmission, and distribution costs to allow for more specific billing. 

23 For example, a customer who takes electricity service from a competitive supplier will still 

24 pay the monopoly for transmission and distribution service, but not generation.

25

26 All tariffs, by definition, are set by regulators whose role it is to allocate the utility’s capital 

27 investments (or rate base) and expenses through the tariff mechanism to ensure that all 

28 authorized costs of the utility are recovered and that the utility receives an appropriate return 

29 on their investments. However, regulators are increasingly looking for alternatives from this 

30 capital investment-based model and toward incentive-based ratemaking of one form or 

31 another. 

32

33 Performance based ratemaking is an example of an alternative form of cost recovery, which 

34 puts more of the utility’s earnings on performance goals and metrics. In part, through these 

35 mechanisms, the distribution utility can become independent on the question of DER 

36 ownership, since their compensation is less directly tied to the return on new additions to the 

37 rate base.

38

39 Rate design: The collection of authorized utility revenue is accomplished via a rate design. 

40 Commercial and Industrial (C&I) customers generally pay for electricity via a tariff that 

41 includes two major components: energy and demand. The demand charge is typically based 

42 on the peak demand within a billing period, either coincident or non-coincident (individual) 

43 with system peak. The construction of the energy component can vary, however, it is 

44 typically either an unchanging flat rate, or a “block rate” that changes (increases or 

45 decreases) at various levels of consumption in the billing period.
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1 Some states have moved industrial and larger commercial customers into time-varying rate 

2 designs, such as time of use or critical peak pricing. In addition to the energy and demand 

3 components, C&I customers may pay separate charges based on their load factor and/or 

4 power factor. For customers who are able to self-supply, they may also pay a stand-by rate 

5 which covers the utility costs to provide electricity to that customer in the event their self6 supply is unavailable.

7

8 Residential rates are predominantly flat energy-based rates; the same rate is paid for each unit 

9 of energy consumed regardless of time or location. Typically, in addition to the base energy 

10 rate, customers pay a “fuel adjustment charge” that varies with the actual cost of generation, 

11 as well as taxes and other additional charges as approved by the regulator. Some 

12 jurisdictions have adopted a block- or tiered-rate construction for residential customers as 

13 well. Residential rates almost never include a demand component. However, in addition to 

14 the energy rate, residential customers also usually pay some kind of monthly customer 

15 charged (fixed fee), regardless of the quantity of energy consumed. Charges for transmission 

16 and distribution services may be accounted for separately or bundled into the energy charge.

17

18 With rare exceptions, residential rates for electricity purchased in the United States do not 

19 vary by time of day (or week), even though electricity generation costs may vary 

20 significantly during the day (or week). Dynamic rates, which — to varying degrees —

21 attempt to reflect in electricity pricing the time-variant nature of electricity costs, are 

22 typically only offered by utilities as an optional pricing program. Time-of-use rates, which 

23 are offered as opt-in programs for residential customers by many U.S. utilities, are structured 

24 to reflect in a broad way the varying cost of energy by hour of the day and/or day of the 

25 week. Time blocks with generally higher cost energy corresponding to peak demand periods 

26 are priced higher than off-peak, lower cost time blocks. In 2019 time-of-use rates became 

27 the default rate structure for all residential customers of the California IOUs, a transition 

28 planned since 2015 affecting more than 20 million customers [171, 172]. Some other utilities 

29 adjust energy pricing seasonally to account for higher energy costs during higher demand 

30 seasons. The two IOUs in Illinois, Commonwealth Edison and Ameren, allow customers to

31 opt into a “real-time pricing” program, in which actual energy costs vary each hour according 

32 to the actual PJM (for ComEd) or MISO (for Ameren) wholesale market price.

33

34 Critical peak pricing and variable peak pricing are mechanisms utilized by a few utilities that 

35 allow for higher energy rates during a limited number of designated peak demand or demand 

36 response events each year. Each “event” is for a specified block of hours, after which pricing 

37 reverts to the normal basis.

38

39 With the exception of a few utilities that offer customers the option to prepay for their 

40 electricity, energy is paid for after the energy is consumed.

41

42 Regulators: The regulator serves as an important check on monopoly market power, and 

43 can be described as acting to impute market pressure upon a monopoly with no natural 

44 competition. This regulatory market pressure includes consideration of utility costs and 

45 revenues, allocating cost recovery across customer classes, and additional requirements often 

46 as determined by state legislatures.
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1

2 Through their oversight capacity, regulators are also responsible for ensuring that the 

3 delivery of electricity is done safely and reliably. This can include oversight for construction 

4 of new power plants and transmission lines, or establishing requirements that ensure 

5 regulated utilities have sufficient electricity resources under contract or otherwise available 

6 to provide service at all times.

7

8 For municipal or cooperative utilities, regulation is often done at the local level by a city 

9 council for a municipal utility or a board comprised of members for a cooperative. Since 

10 neither the municipal nor the cooperative utility are for-profit, rates are set to recover the 

11 utility’s costs.
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1 Appendix F – Distribution Platforms and Markets

2

3 There are a number of architectural, resource, and economic structures that can be employed 

4 to facilitate the transition to a more flexible and resilient system that better incorporates and 

5 values customer contributions to the system. This Framework is agnostic on the specific 

6 implementation choices made to achieve those ends, and it is important to note that any 

7 economic solution will need to suit the circumstances of each state, utility, and regulatory 

8 authority. 

9

10 When considering the view of planning for, integrating, and investing in the grid to improve 

11 operational flexibility and resilience, and accommodate increasing numbers and types of 

12 technology, distribution platforms and market structures may be a useful model for how to 

13 integrate new technologies at low cost and high efficiency, and to maximize the benefits of 

14 interoperability investments. Two of the more commonly referred to options are distribution 

15 system platforms and transactive energy markets, which are summarized here.

16

17 Distribution System Platforms: As currently envisioned, a future distribution system 

18 operator (DSO) would provide a distribution-level market platform that enables a broad 

range of DER services90 19 to be incorporated into an open-access distribution level market. 

20 The value and pricing of these services would be transparent and include both a local and 

21 system-level valuation component.

22

23 A distribution-level market platform would connect DER, customers, aggregators, and local 

markets operated by energy service providers,91 24 allowing for the active exchange of services 

25 and resources between a variety of stakeholders and not just via the traditional utility26 customer relationship. The value of DER would be dynamically calculated based on the 

27 instantaneous location-based value of each resource, and the platform would enable both 

28 peer-to-peer and peer-to-grid transactions. The platform would balance supply and demand 

29 through the development of a schedule of requirements based on pre-existing commitments, 

30 load forecasts, and generation forecasts. The platform would communicate transaction prices 

31 to DER and aggregators and then, based on actual operating conditions, readjust pricing as 

32 required to ensure supply/demand balance.

33

34 The role of the DSO, as outlined in recent regulatory activities in California and New York, 

35 is designed to facilitate the growth of DER on the distribution grid in a manner that should 

36 lead to a more optimal deployment of these resources. These two are the only states that 

37 have yet taken significant steps toward redefining the role of the distribution utility in 

38 response to DER proliferation, in which the DSO is viewed as a transformation of the role of 

39 the existing utility. More generally, a DSO should facilitate a more optimal development of 

40 the grid [173].

41

42 In California, the CPUC has defined several new capabilities for distribution utilities. 

43 Among the most significant of these, each utility is required to perform hosting capacity 

44 analyses, including a locational value analysis of each grid segment, and to publish the 

90 For example: voltage and reactive power support, power quality, power flow control, and reliability services. 91 For example: demand response aggregation, or electric vehicle charge management.
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1 results of these analyses into a publicly-available geographic interface. By performing these 

2 analyses and making this information available, DER providers and developers have an 

3 enhanced understanding of the potential value for their investments.

4

5 As a more advanced extension of this concept, the DSO would develop scenarios to 

6 remediate existing issues on the distribution grid. The DSO, in addition to considering 

traditional “wires-based” solutions92 7 would consider on an equal basis the potential value of 

“non-wires” solution alternatives.93 8 The DSO would then conduct a series of modelling and 

9 simulation studies to determine which of the alternative solutions would most optimally 

10 address the existing grid issues based on forecasted conditions. If a non-wires solution 

11 proves to be the preferred approach, the DSO would publish the results of this analysis for 

12 public consumption and facilitate the deployment of the preferred solution through economic 

13 incentive.

14

15 For this approach to work, the DSO has to be indifferent to both the nature and ownership of 

16 the solution, and must be neutral in its role of coordinating a distribution-level market. This 

17 independence and objectivity can only be realized if the financial incentives that the DSO has 

18 are consistent with this impartiality, and so the traditional cost-of-service and rate base 

19 structure that drives most distribution utility revenue streams would have to be replaced with 

20 other mechanisms.

21

22 Transactive Energy Markets: The purpose of transactive energy is to provide least-cost 

23 energy using typical market supply and demand principles. Transactive energy has been 

24 defined as “a system of economic and control mechanisms that allows the dynamic balance 

25 of supply and demand across the entire electrical infrastructure using value as a key 

26 operational parameter.” [174] Transactive energy can be thought of as a robust electricity 

27 marketplace in which economic transactions provide the necessary foundation for balancing 

28 of supply and demand and maintaining the integrity of the grid. 

29

30 Through the near-real-time communication of pricing signals, market participants would 

respond with the necessary resources needed for effective grid operation.94 31 In effect, 

32 operation of the grid is accomplished “economically,” with a pure financial engine driving 

33 the exchange of required goods and services. Although much work needs to be done to 

34 translate the notion of transactive energy into practice, at its core transactive approaches 

35 present opportunities to create a platform in which the broadest set of economic resources are 

36 always participating in maintaining the grid. The ideal outcome is therefore a more optimal 

37 operation of the grid than could otherwise be achieved.

38

39 Transactive energy also creates entirely new mechanisms for customers to interact with the 

40 grid. Instead of just being passive price takers in an artificially static procurement process, 

41 customers become active participants in a dynamic energy market. In doing so, customer 

42 roles evolve from purely one of consumption to a supplier of energy and related services. 

43 Transactive energy approaches have been extensively demonstrated and analyzed [32].

92 Examples of wires-based solutions include re-conductoring the system and equipment upgrades. 93 Examples of non-wires alternatives include distributed generation, demand response, and energy storage. 94 Examples of the necessary resources include energy, reactive power, or ancillary services.
158

1 Appendix G – Smart Grid Cybersecurity Profile Subcategory Prioritization and Considerations Matrices

2

3 This appendix includes the excerpted tables that identify which Subcategories directly assist power system owners/operators in 

4 achieving the business objectives identified in Section 5.1.4, as well as the grid-specific considerations identified for each 

5 Subcategory. These prioritizations and considerations form the primary elements of the Smart Grid Cybersecurity Risk Profile, the 

6 full version of which is a publicly available NIST publication [124].

7

8 G.1 – Identify Function

9

10 The Identify Function is critical in the development of the foundation for cybersecurity management, and in the understanding of 

11 cyber risk to systems, assets, data, and capabilities. This Function guides the owner/operator in the development of the foundation for 

12 cybersecurity management, and in the understanding of cyber risk to systems, assets, data, and capabilities. The activities in the Asset 

13 Management, Business Environment, Risk Assessment, Risk Management Strategy, and Supply Chain Risk Management are the 

14 primary security areas that address protections for the four business objectives. The Subcategories below are derived from the 

15 Cybersecurity Framework Core, which includes descriptions and informative references for each Subcategory. 

16

17 Table 16 – Identify function subcategory prioritization and considerations

Maintain 

Safety

Maintain 

Reliability

Maintain 

Resilience

Support Grid 

Modernization Considerations for Power System Owners/Operators

Category Subcategories

Asset 

Management ID.AM-1 ID.AM-1 ID.AM-1 ID.AM-1

Knowing hardware assets is critical for maintaining safety, 

reliability, and resilience, as well as facilitating the transition to 

the modern grid. Legacy and modernized assets95 need to be 

known and understood. As modernized grids become more 

distributed, power system owners/operators need to be 

accountable for all distributed assets that they own.

95 Modernized assets/devices refers to power system devices that utilize two-way communication technologies and advanced sensing capabilities to help improve grid operations.
159

Maintain 

Safety

Maintain 

Reliability

Maintain 

Resilience

Support Grid 

Modernization Considerations for Power System Owners/Operators

Category Subcategories

ID ID.AM-2 ID.AM-2 ID.AM-2 ID.AM-2

Knowing software assets is critical for maintaining reliability, and 

resilience, as well as facilitating the transition to the modern 

grid. Legacy and modernized assets need to be known and 

understood. This especially applies to modernized assets 

because the sophisticated logic that they execute is driven by 

software.

ID.AM-3 ID.AM-3 ID.AM-3 ID.AM-3

Understanding communication and data flows is important to 

ensure reliability and resilience. Communications networks are 

critical for modernized grids, and understanding the different 

types of data flows (control, monitoring, and management) will 

provide critical information for managing those flows within 

modernized infrastructures and between modernized and 

traditional infrastructure.

ID.AM-4 ID.AM-4 ID.AM-4 ID.AM-4

The presence of external information systems may have many 

impacts on the power grid. Grid reliability and resilience may be 

impacted if power system owners/operators are not aware of all 

power systems, customer-owned devices, and any other thirdparty systems connected to the distribution system. With 

respect to supporting grid modernization, traditional and 

modernized parts of the grid will exist side by side within a single 

power system owner/operator and across power system 

ownership lines. Awareness of external information systems 

that manage both traditional and modernized components is 

important to assure security of both Information Technology (IT) 

and Operational Technology (OT) infrastructures.

ID.AM-5 ID.AM-5 ID.AM-5 ID.AM-5

Power systems contain many types of resources, including 

devices, data, personnel, and software. Resources directly 

involved in the distribution of power should be prioritized ahead 

of business systems.

ID.AM-6 ID.AM-6 ID.AM-6 ID.AM-6

Identifying all power system stakeholders and their roles and 

responsibilities with respect to maintaining and restoring power 

is critical to all four business requirements.
160

Maintain 

Safety

Maintain 

Reliability

Maintain 

Resilience

Support Grid 

Modernization Considerations for Power System Owners/Operators

Category Subcategories

Business 

Environment

ID.BE-1 ID.BE-1 ID.BE-1 ID.BE-1

"Supply chain" in this Subcategory includes IT and OT products 

and services business partners, and other relevant third parties 

that support power delivery. As such it impacts the reliable flow 

of power and resiliency efforts including the flow of power from 

modernized parts of the grid.

ID.BE-2 ID.BE-2 ID.BE-2 ID.BE-2

Power system owners/operators should understand their 

organization's placement in the grid infrastructure in order to 

manage potential cascading effects on the grid. The magnitude 

of potential cascading effects should be understood. Because 

the modernized grid incorporates distributed generation, the 

points of integration of distributed resources with the larger grid 

should be well understood. These points of integration may 

include generation, transmission, distribution, customers, and 

third-party owners/operators of distributed resources. 

ID.BE-3 ID.BE-3 ID.BE-3 ID.BE-3

Power system owners/operators have a variety of state and local 

regulatory requirements that influence their mission and 

objectives. See ID.GV-3.

ID.BE-4 ID.BE-4 ID.BE-4 ID.BE-4

Understanding power system dependencies helps maintain

reliability and resilience. It also facilitates grid modernization 

through providing necessary information to plan and implement 

grid modernization initiatives. Having a thorough understanding 

of dependencies within the power system can also improve 

safety. The power system owner/operator should identify all 

sources and loads that require power, understand information 

about the loads, sources, and power delivery network at any 

given time, and use this information to control the flow of power 

from source to loads.

ID.BE-5 ID.BE-5 ID.BE-5 ID.BE-5

Power system owners/operators should understand and 

implement the specific requirements to ensure resilient 

operation of the power system.
161

Maintain 

Safety

Maintain 

Reliability

Maintain 

Resilience

Support Grid 

Modernization Considerations for Power System Owners/Operators

Category Subcategories

Governance

ID.GV-1 ID.GV-1 ID.GV-1 ID.GV-1

Information security policy drives a set of coherent security 

requirements throughout the organization. In this context, 

security policy should support safety, reliability, resilience, 

privacy, and other related concerns. Also within this context, 

grid components are cyber-physical systems (CPS) themselves, 

composed into a more complex, networked cyber-physical 

system of systems. The NIST CPS Public Working Group (PWG) 

Framework provides a set of relevant concerns. Organizational 

informational security policy should address OT and IT 

environments and how they integrate, the complexity of 

external partnerships, as well as cover both traditional and 

modernized environments.

ID.GV-2 ID.GV-2 ID.GV-2 ID.GV-2

Information security roles and responsibilities and their 

coordination with external partners directly affect all 

requirements. In the context of the modernized grid, external 

parties include the owners of distributed resources.

ID.GV-3 ID.GV-3 ID.GV-3 ID.GV-3

Legal and regulatory requirements regarding cybersecurity are 

especially applicable in the highly regulated critical infrastructure 

environment of electric power generation, transmission, and 

distribution. The modernized grid has additional regulatory 

requirements that should be considered here.

ID.GV-4 ID.GV-4 ID.GV-4 ID.GV-4

Because the grid is a large cyber-physical system, governance 

and risk management processes should address all risks, not just 

cybersecurity.

Risk 

Assessment ID.RA-1 ID.RA-1 ID.RA-1 ID.RA-1

Identifying and documenting asset vulnerabilities can be 

performed as part of a risk assessment. Vulnerabilities from 

traditional and modernized environments should be included, 

especially cyber-physical devices in the modern grid.
162

Maintain 

Safety

Maintain 

Reliability

Maintain 

Resilience

Support Grid 

Modernization Considerations for Power System Owners/Operators

Category Subcategories

ID.RA-2 ID.RA-2 ID.RA-2 ID.RA-2

Modernized devices need to be included in information sharing. 

However, these newer devices that are a part of grid 

modernization are not yet well-addressed within the information 

sharing forums of the power system owner/operator 

community.

ID.RA-3 ID.RA-3 ID.RA-3 ID.RA-3

Potential threats are greatly increased in the more complex 

environment of the modernized grid, thereby requiring more 

extensive analysis. The environment is more complex because 

1) the high number of devices exponentially increases the attack 

surface; 2) these devices may have different and distributed 

ownership; 3) the devices are likely heterogeneous; and 4) the 

overall high interconnectivity of the modernized grid.

ID.RA-4 ID.RA-4 ID.RA-4 ID.RA-4

The modernized grid will have additional and more complex 

business impacts due to its distributed and multi-owner nature 

and complex regulatory landscape. 

ID.RA-5 ID.RA-5 ID.RA-5 ID.RA-5

Power systems owners/operators should consider threats, 

vulnerabilities, and impacts to the converged IT/OT 

environment, including traditional and modernized components.

ID.RA-6 ID.RA-6 ID.RA-6 ID.RA-6

The complexity of the stakeholder landscape in the modernized 

grid can make the risk responses of power system 

owners/operators more complicated. Power system 

owners/operators will need to consider how proposed risk 

responses will impact interconnected stakeholders.

Risk 

Management 

Strategy

ID.RM-1 ID.RM-1 ID.RM-1 ID.RM-1 The complexity of the stakeholder landscape in the modernized 

grid can make risk management processes more complicated.

ID.RM-2 ID.RM-2 ID.RM-2 ID.RM-2

Power system owners/operators should consider the 

development of a comprehensive strategy to manage risk, 

including integrating the modernized components of the grid 

into the determination and description of risk tolerance. 
163

Maintain 

Safety

Maintain 

Reliability

Maintain 

Resilience

Support Grid 

Modernization Considerations for Power System Owners/Operators

Category Subcategories

ID.RM-3 ID.RM-3 ID.RM-3 ID.RM-3

When determining organizational risk tolerance, power system 

owners/operators should consider the potential cascading 

effects on the immediate geographic area, larger region, and the 

sector overall. 

Supply Chain 

Risk 

Management

ID.SC-1 ID.SC-1 ID.SC-1 ID.SC-1

Power system owners/operators rely on integrators, Industrial 

Control System (ICS) vendors, and commercial off-the-shelf 

(COTS) providers to design and implement networks, systems, 

and applications that run the grid. As power systems 

owners/operators modernize their grids, their supply chains 

increasingly include third party service providers and distributed 

generation owners/operators. Power system owners/operators 

therefore need to have robust processes for managing 

cybersecurity risks stemming from these supply chains that 

include all relevant members of this diverse ecosystem. 

ID.SC-2 ID.SC-2 ID.SC-2 ID.SC-2

Organizational supply chain risk management processes should 

be continuously improved regardless of whether the 

environment is traditional or modernized. 

ID.SC-3 ID.SC-3 ID.SC-3 ID.SC-3

When power systems transcend organizational boundaries, it 

may be beneficial for power system owners/operators to 

mutually agree on a set of appropriate security requirements in 

order to manage security risks. In addition to security 

requirements in supplier agreements, power system 

owners/operators are encouraged to establish a set of security 

requirements with their third-party partners. These agreements

may be mutual, as in power system owners/operators would 

also be agreeing to a set of security requirements they would 

commit to abide by. This is a key risk management 

consideration for power system owners/operators.
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Category Subcategories

ID.SC-4 ID.SC-4 ID.SC-4 ID.SC-4

Assessments are required to understand whether suppliers and 

third parties are continuously following agreed-upon 

cybersecurity requirements. Power system owners/operators 

should consider that lack of these assurances can have an impact 

on all critical business/mission goals.

ID.SC-5 ID.SC-5 ID.SC-5 ID.SC-5

Power system owners/operators should ensure that the 

modernized (including distributed) power environment is 

accounted for in response and recovery plans. Testing of these 

plans helps manage grid modernization efforts. Additionally, 

suppliers and 3rd-party providers should be included in testing of 

these plans. Suppliers and 3rd-party providers are critical to 

orderly restoration after incidents; if they are not properly 

integrated in testing efforts, it may have an impact on all critical 

business/mission goals.

1
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1 G.2 – Protect Function

2

3 The Protect Function is critical to limit the impact of a potential cybersecurity event. Identity Management and Access Control, 

4 Awareness and Training, Information Protection Processes, Maintenance, and Protective Technology are the priority security focus 

5 areas. Identity Management and Access Control identifies and regulates personnel ingress and egress. Awareness and Training and the 

6 Protection Processes prepare the workforce to achieve cybersecurity. Protective technology implements security decisions. The 

7 Subcategories below are derived from the Cybersecurity Framework Core, which includes descriptions and informative references for 

8 each Subcategory.

9

10 Table 17 – Protect function subcategory prioritization and considerations

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Category Subcategories

Access Control

PR.AC-1 PR.AC-1 PR.AC-1 PR.AC-1 Identity management is essential for all users, devices, and 

processes in both traditional and modernized environments.

PR.AC-2 PR.AC-2 PR.AC-2 PR.AC-2

Power system owners/operators should control physical access 

to the power system components as needed, including 

modernized and distributed grid components. Power system 

owners/operators should consider the limitations of 

maintaining physical access to devices on other premises, 

especially those devices that are owned by a 3rd party.

PR PR.AC-3 PR.AC-3 PR.AC-3 PR.AC-3

Many grid components are maintained remotely and such 

remote access should be secured. For modernized 

environments, consider the limitations of managing remote 

access to devices that are owned by a 3rd party, such as 

distributed resources.
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Category Subcategories

PR.AC-4 PR.AC-4 PR.AC-4 PR.AC-4

Least privilege is important for limiting permissions and 

authorizations to manage connected devices. This reduces risks 

of unapproved operations which may create negative impacts 

to safety, reliability, and resilience. For example, excessive 

privileges may create an opportunity for compromise during 

power restoration. Grid modernization efforts should ensure 

that least privilege principles are designed into and 

implemented in the modernized grid.

PR.AC-5 PR.AC-5 PR.AC-5 PR.AC-5

Network segmentation is an important tool for containing 

potential incidents (safety, reliability), and limiting damage 

from incidents (resilience). Grid modernization efforts should 

consider segmenting networks from the design stage into 

operations (e.g., DER devices could be segmented to limit 

exposure to the rest of the power system infrastructure).

PR.AC-6 PR.AC-6 PR.AC-6 PR.AC-6

In the power system, the safe delivery of reliable power is 

paramount. For this reason, there may be situations (e.g., 

emergency maintenance or need to restore power) in which the 

binding and proofing of credentials may interfere with safety, 

reliability, and resilience. Power system owners/operators will 

need to consider any risks introduced if identities are not 

proofed and bound to credentials and if those credentials are 

not required for certain user actions.

PR.AC-7 PR.AC-7 PR.AC-7 PR.AC-7

Devices should be authenticated before connecting to the grid 

network to ensure that only authorized devices are allowed to 

connect. Proper authentication of users, devices, and assets 

helps ensure safety and reliability. Special care will need to be 

taken to ensure that modernized devices are also authenticated 

to the grid network.
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Category Subcategories

Awareness and 

Training

PR.AT-1 PR.AT-1 PR.AT-1 PR.AT-1

User training needs to include a mention that modernization of 

a grid affects cybersecurity. For example, the dependence on 

bi-directional, real-time data flows increases the importance of 

data integrity. Security awareness training should be provided 

to all users, including manufacturing system users and 

managers. Training could include, for example, a basic 

understanding of the protections and user actions needed to 

maintain security of the system, procedures for responding to 

suspected cybersecurity incidents, and awareness of 

operational security. Also, it is recommended to incorporate 

threat recognition and reporting into security awareness 

training.

PR.AT-2 PR.AT-2 PR.AT-2 PR.AT-2

Privileged user training needs to include a mention that legacy 

to non-legacy migration has impact to cybersecurity. For 

example, the dependence on bi-directional, real-time data 

flows increases the importance of data integrity.

PR.AT-3 PR.AT-3 PR.AT-3 PR.AT-3

The stakeholder landscape is complicated in the modernized 

grid and power system owners/operators will need to include 

roles and responsibilities of all relevant stakeholders, including 

third parties.

PR.AT-4 PR.AT-4 PR.AT-4 PR.AT-4

Executives need to understand the implications of business 

decisions (e.g., grid modernization) on cybersecurity, which can 

impact the larger business/mission goals 

PR.AT-5 PR.AT-5 PR.AT-5 PR.AT-5

Training and responsibilities for physical and information 

security personnel need to be tailored to the unique threats 

and risks of the grid modernization environment as well as the 

distributed and multi-owner nature of the environment. 
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Data Security

PR.DS-1 PR.DS-1 PR.DS-1 PR.DS-1

In the case of power grid systems, protecting data-at-rest 

should apply to protecting the integrity of device settings. If 

tampered with, device settings may cause a safety or reliability 

issue.

PR.DS-2 PR.DS-2 PR.DS-2 PR.DS-2

In the case of power grid systems, protecting data in-transit is 

an important tool to help protect the integrity of control 

information and device settings. Loss of integrity of control 

information may cause a safety or reliability issue. Power 

system owners/operators should consider the potential for 

resource-intensive cryptographic mechanisms to interfere with 

the functional performance of control systems and use 

additional methods to protect data in transit when less 

resource intensive cryptographic mechanisms are used. 

PR.DS-3 PR.DS-3 PR.DS-3 PR.DS-3

Power system owners/operators need to be aware of all 

distributed, modernized assets they own and manage them 

throughout the life cycle. IT components embedded in OT 

devices within the grid modernization infrastructure (e.g., 

power control and delivery) may present challenges of 

ownership/contractual agreements with the manufacturers. 

During disposal of assets, special care should be taken to not 

expose device configuration data. The integrity of device 

configuration data should be protected to not impact future 

safety and reliability.

PR.DS-4 PR.DS-4 PR.DS-4 PR.DS-4 Understanding capacity requirements is critical for power 

system reliability and resilience. 
169

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Category Subcategories

PR.DS-5 PR.DS-5 PR.DS-5 PR.DS-5

Data can be used to understand system behavior and devise 

methods to attack the system. Therefore, protection from data 

leaks is important for safety and reliability.

PR.DS-6 PR.DS-6 PR.DS-6 PR.DS-6

The integrity of information and of software/firmware running 

on system components is critical to all business/mission 

requirements. 

PR.DS-7 PR.DS-7 PR.DS-7 PR.DS-7

The separation of development and testing environments is 

critical to ensure testing does not accidentally impact 

operational systems. Insufficient separation could directly 

impact safety, reliability, and resilience. This applies to both 

traditional and modernized environments equally; grid 

modernization is not specifically highlighted. This should be 

already done for the traditional environment and should also 

apply to modernized environments. However, it should be 

noted that applying this to distributed environments may be 

challenging due to their scope.

PR.DS-8 PR.DS-8 PR.DS-8 PR.DS-8 The integrity of power system hardware is critical to safety, 

reliability, resilience, and grid modernization.

Information 

Protection 

Processes and 

Procedures

PR.IP-1 PR.IP-1 PR.IP-1 PR.IP-1

Baseline configurations are needed for all devices that are 

owned by a power system owner/operator. However, power 

system owner/operators should consider that they may have 

little or no control over the configuration of devices owned by 

other stakeholders connecting to the grid. Creating and 

maintaining baseline configurations supports the safety, 

reliability, and resilience (by providing known state to restore 

equipment to) of the power grid. Grid modernization efforts 

are also supported by having a standard configuration for all 

devices.
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Category Subcategories

PR.IP-2 PR.IP-2 PR.IP-2 PR.IP-2

Implementing a systems development lifecycle ensures quality 

and predictable performance of systems and networks. It is 

critical for safety and reliability. While also important for the 

maintain resilience and support grid modernization business 

objectives, the safety and reliability objectives will drive the 

systems development lifecycle requirements and so only those 

two goals are selected.

PR.IP-3 PR.IP-3 PR.IP-3 PR.IP-3

Configuration change control processes support safety, 

reliability, resilience (known state to restore to), and transition 

to modernized grid. Power system owners/operators should 

consider how organizational configuration change control 

processes will include devices owned by third parties

PR.IP-4 PR.IP-4 PR.IP-4 PR.IP-4

Backups are essential for retaining device configuration 

information so that devices can be recovered and restored to 

proper operational states. Modernized grids are especially 

susceptible because modern devices have more programmable 

logic in them. Special consideration should be taken to address 

backups of devices owned by third parties.

PR.IP-5 PR.IP-5 PR.IP-5 PR.IP-5

Physical security policies are important for safety and reliability 

of the power grid. Physical access to sensors can lead to 

sensors being used as attack vectors. Physical security policies 

also support the integration of distributed, modernized devices 

into the grid.

PR.IP-6 PR.IP-6 PR.IP-6 PR.IP-6 The destruction of data is not directly applicable to these 

business/mission requirements.

PR.IP-7 PR.IP-7 PR.IP-7 PR.IP-7

Protection processes should be continuously improved 

regardless of whether the power system environment is 

traditional or modernized. 

PR.IP-8 PR.IP-8 PR.IP-8 PR.IP-8 Sharing the effectiveness of protection technologies is not 

directly applicable to these business/mission requirements.
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Category Subcategories

PR.IP-9 PR.IP-9 PR.IP-9 PR.IP-9

Power system owners/operators need to be sure to include the 

modernized environment/devices in the response and recovery 

plans and their testing to help manage grid modernization 

efforts. They should also ensure that the plans address the 

collaboration between IT and OT personnel and the distributed 

nature of modernized environments.

PR.IP-10 PR.IP-10 PR.IP-10 PR.IP-10

Power system owners/operators need to be sure to include the 

modernized environment/devices in cybersecurity response 

and recovery plans and their testing to help manage grid 

modernization efforts. The plans need to address the 

collaboration between IT and OT personnel as well as the 

distributed nature of modernized environments.

PR.IP-11 PR.IP-11 PR.IP-11 PR.IP-11

Processes and procedures for including cybersecurity in human 

resources practices are the same for both traditional and 

modernized environments. Therefore, no special 

accommodations are required for the modernized grid.

PR.IP-12 PR.IP-12 PR.IP-12 PR.IP-12

Modernized distributed energy resources can have 

vulnerabilities that may allow new and unaccounted threat 

vectors to the power grid. Power system owners/operators 

should consider how externally-owned devices and third-party 

owners/operators will be included in a vulnerability 

management plan. 

Maintenance

PR.MA-1 PR.MA-1 PR.MA-1 PR.MA-1 Special care needs to be taken when devices are owned by third 

parties, as may be the case in modernized environments.

PR.MA-2 PR.MA-2 PR.MA-2 PR.MA-2

Power system owners/operators need to be aware of any 

remote access capabilities that the device vendor may have to 

equipment. This is extremely important in energy 

environments due to the distributed nature, geographical 

dispersion, and the mission need for remote maintenance of 

both legacy and modernized devices.
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Category Subcategories

Protective 

Technology

PR.PT-1 PR.PT-1 PR.PT-1 PR.PT-1

Audit logs capture information that will be helpful during an 

attack to find anomalies and potentially limit the impact or stop 

the incident from inflicting greater damage (helps safety). 

Capturing and monitoring audit logs is also important for 

managing cybersecurity risks to grid modernization. These 

audit logs may provide visibility into the activities and traffic 

related to these distributed devices.

PR.PT-2 PR.PT-2 PR.PT-2 PR.PT-2

Protecting and restricting the use of removable media on 

modernized devices has the same considerations as on legacy 

devices.

PR.PT-3 PR.PT-3 PR.PT-3 PR.PT-3

Power system owners/operators should consider how the 

principle of least functionality will be applied to third-party 

assets connected to their grid.

PR.PT-4 PR.PT-4 PR.PT-4 PR.PT-4

Distributed multi-ownership of some modern grid (e.g., DER) 

environments may make it challenging to protect 

communications and control networks.

PR.PT-5 PR.PT-5 PR.PT-5 PR.PT-5 Power system owners/operators should consider all possible 

ways to achieve resiliency requirements.

1
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1 G.3 – Detect Function

2

3 The Detect Function enables timely discovery of cybersecurity events. Real time awareness and continuous monitoring of the systems 

4 is critical to detect cybersecurity events. The Subcategories below are derived from the Cybersecurity Framework Core, which 

5 includes descriptions and informative references for each Subcategory.

6

7 Table 18 – Detect function subcategory prioritization and considerations

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Category Subcategories

Anomalies and 

Events

DE.AE-1 DE.AE-1 DE.AE-1 DE.AE-1

A baseline of network operations and expected data flows is 

extremely important in the OT context because information 

flows are predictable, and control systems generally have few 

users. Understanding the control information flows will help 

monitor and detect unusual network behavior and allow for 

timely response. This applies to both traditional and 

modernized grid environments.

DE.AE-2 DE.AE-2 DE.AE-2 DE.AE-2

Analyzing detected cybersecurity events is critical for safety, 

reliability, and resilience. There are no special considerations 

for modernized parts of the infrastructure.

DE DE.AE-3 DE.AE-3 DE.AE-3 DE.AE-3

When collecting and aggregating data from third-party 

devices, the devices and the data should be authenticated 

and validated. Without this authentication and validation, 

power system owners/operators should carefully consider 

whether those devices and their data can be trusted.

DE.AE-4 DE.AE-4 DE.AE-4 DE.AE-4

Determining the impact of detected cybersecurity events is 

critical for safety, reliability, and resilience. There are no 

special considerations for modernized parts of the 

infrastructure.

DE.AE-5 DE.AE-5 DE.AE-5 DE.AE-5

Establishing incident alert thresholds is critical for safety, 

reliability, and resilience. This practice applies to both 

traditional and modernized parts of the grid.
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Category Subcategories

Security 

Continuous 

Monitoring

DE.CM-1 DE.CM-1 DE.CM-1 DE.CM-1

Neglecting to monitor the grid for cybersecurity events may 

result in missing an event with implications and impact. For 

grid modernization, monitoring has to be built in for the 

future. While the selection of safety may be surprising, not 

monitoring substantially increases the risk of not knowing 

that there may be safety impacts and being unable to reduce 

or eliminate them.

DE.CM-2 DE.CM-2 DE.CM-2 DE.CM-2

Monitoring the physical environment for cybersecurity events 

is critical for safety, reliability, and resilience. There are no 

special considerations for modernized parts of the 

infrastructure.

DE.CM-3 DE.CM-3 DE.CM-3 DE.CM-3

Monitoring personnel activity for cybersecurity events is 

critical for safety, reliability, and resilience. There are no 

special considerations for modernized parts of the 

infrastructure.

DE.CM-4 DE.CM-4 DE.CM-4 DE.CM-4

Power system owners/operators should consider using 

malicious code detection methodologies in both traditional 

and modernized infrastructure. These devices contain 

complex software which makes them vulnerable to cyber 

attacks.

DE.CM-5 DE.CM-5 DE.CM-5 DE.CM-5

Detecting unauthorized mobile code is critical for safety, 

reliability, and resilience. There are no special considerations 

for modernized parts of the infrastructure.

DE.CM-6 DE.CM-6 DE.CM-6 DE.CM-6

Power system owners/operators rely on vendors and external 

service providers for many capabilities, including industrial 

control systems and communications networks required to 

operate the grid. Whether service providers are accessing IT 

or OT environments, those activities should be monitored to 

ensure mitigating actions can be taken in case of attack 

stemming from external connections. 
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Category Subcategories

DE.CM-7 DE.CM-7 DE.CM-7 DE.CM-7

Unauthorized personnel, connections, devices, or software 

introduce risks into IT and OT, and may impact grid 

operations. Any connections to IT and OT systems and 

networks should be authenticated to ensure that only 

approved and trusted parties gain access to those systems 

and networks.

DE.CM-8 DE.CM-8 DE.CM-8 DE.CM-8

Performing vulnerability scans is required to identify 

vulnerabilities in critical infrastructure. For modernized 

environments, power system owners/operators may need to 

consider an agreement to scan 3rd party-owned devices that 

are connected to their grid.

Detection 

Processes

DE.DP-1 DE.DP-1 DE.DP-1 DE.DP-1

Knowing roles and responsibilities with respect to detection is 

critical to all four business goals. This includes restoration 

across power system ownership lines and within a single 

power system owner/operator with traditional and 

modernized components and networks. Distributed 

resources owners/operators may also have a role and 

responsibilities in detection activities.

DE.DP-2 DE.DP-2 DE.DP-2 DE.DP-2

Power system owners/operators need to ensure that 

detection activities comply with jurisdiction-specific safety 

requirements.

DE.DP-3 DE.DP-3 DE.DP-3 DE.DP-3

Power system owners/operators should consider any 

potential negative impact to the power system due to testing 

of detection processes. The owners/operators of distributed 

modernized devices may also need to participate in this 

testing. 

DE.DP-4 DE.DP-4 DE.DP-4 DE.DP-4

Event detection information communication includes 

communicating detection events across traditional and 

modernized environments as well as between power system 

owners/operators in the modernized grid.

DE.DP-5 DE.DP-5 DE.DP-5 DE.DP-5 Detection processes should be continuously improved.

1
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1 G.4 – Respond Function 

2

3 The Respond Function supports the ability to contain the impact of a potential cybersecurity event. Rapid and effective response and 

4 communication to cybersecurity incidents is critical in protecting personnel and environmental safety. Situational awareness to the 

5 event unfolding is needed to properly address it. The Subcategories below are derived from the Cybersecurity Framework Core, which 

6 includes descriptions and informative references for each Subcategory.

7

8 Table 19 – Respond function subcategory prioritization and considerations

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Considerations for Power Systems Owners/Operators

Category Subcategories

Response 

Planning

RS.RP-1 RS.RP-1 RS.RP-1 RS.RP-1 Response plan execution applies in both traditional and 

modernized environments.

Communications

RS.CO-1 RS.CO-1 RS.CO-1 RS.CO-1 Knowing roles and responsibilities with respect to 

response and grid restoration is critical to all four 

business goals. This includes restoration across power 

system ownership lines and within a single power 

system owner/operator with integration of traditional 

and modernized components and networks.

RS

RS.CO-2 RS.CO-2 RS.CO-2 RS.CO-2 Having established criteria for reporting incidents helps 

support safety objectives to ensure that safety 

considerations are a part of incident response. 

Furthermore, resilience benefits from thoughtful criteria.

RS.CO-3 RS.CO-3 RS.CO-3 RS.CO-3 Assuming that the event response information is shared 

once an incident has occurred, this Subcategory 

outcome supports resilience, rather than reliability. 

Sharing of information is important to ensure safety of 

restoration crews and has to be executed across 

traditional and modernized systems and components.

RS.CO-4 RS.CO-4 RS.CO-4 RS.CO-4 Power system owners/operators should consider that 

the modernized grid is expected to have an expanded

set of stakeholders that includes distributed resources 

owners/operators.
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Category Subcategories

RS.CO-5 RS.CO-5 RS.CO-5 RS.CO-5 Sharing information across power system boundaries is 

important, especially when some of the power systems 

are modernized and some are not. In this context, 

external stakeholders are assumed to include 

neighboring power system owners/operators. 

Analysis

RS.AN-1 RS.AN-1 RS.AN-1 RS.AN-1 Investigating notifications from detection systems is 

important for safety, reliability, and resilience. There are 

no special considerations for modernized parts of the 

infrastructure.

RS.AN-2 RS.AN-2 RS.AN-2 RS.AN-2 Power system owners/operators should take care to 

understand any similarities and differences in impacts 

between the traditional and modernized environments. 

RS.AN-3 RS.AN-3 RS.AN-3 RS.AN-3 Performing forensics of incidents is critical for safety and 

resilience.

RS.AN-4 RS.AN-4 RS.AN-4 RS.AN-4 Categorizing incidents is critical for safety and resilience.

RS.AN-5 RS.AN-5 RS.AN-5 RS.AN-5 Having processes for receiving and analyzing 

vulnerability information is important for reliability, 

resilience, and the modernized grid because devices in 

the modernized grid are smarter than the legacy devices 

and have their own vulnerabilities. Safety will benefit 

indirectly from these activities.

Mitigation

RS.MI-1 RS.MI-1 RS.MI-1 RS.MI-1 Containing incidents is critical for safety and resilience, 

since once an incident occurs, reliability is at risk and 

may already have been affected. Containing incidents is 

important for both traditional and modernized 

infrastructures.

RS.MI-2 RS.MI-2 RS.MI-2 RS.MI-2 Mitigating incidents is critical for safety and resilience, 

since once an incident occurs, reliability is at risk and 

may already have been affected depending on the 

nature of the incident. Mitigating incidents is important 

for both traditional and modernized infrastructures.
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Category Subcategories

RS.MI-3 RS.MI-3 RS.MI-3 RS.MI-3 Newer devices are likely to be more vulnerable because 

they are interconnected and more complex than legacy 

devices. Not patching will hinder the ability of power 

system owners/operators to be resilient and reliable. 

Processes should be in place to receive vulnerability 

information from vendors, as well as to share 

vulnerability information with device owners/operators 

across power systems that may have different 

ownership. 

Improvements

RS.IM-1 RS.IM-1 RS.IM-1 RS.IM-1 Lessons learned will improve future safety, reliability, 

resilience, and grid modernization.

RS.IM-2 RS.IM-2 RS.IM-2 RS.IM-2 Updating recovery strategies will improve future safety, 

reliability, resilience, and grid modernization.

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1 G.5 – Recover Function

2

3 The Recover Function supports timely recovery to normal operations to reduce the impact of a cybersecurity event. Defined Recovery 

4 objectives are needed when recovering from disruptions. The Subcategories below are derived from the Cybersecurity Framework 

5 Core, which includes descriptions and informative references for each Subcategory. 

6

7 Table 20 – Recover function subcategory prioritization and considerations

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Modernization

Considerations for Power Systems Owners/Operators

Category Subcategories

RE

Recovery Planning

RC.RP-1 RC.RP-1 RC.RP-1 RC.RP-1 There are implications to the safety of power system 

owner/operator workers (e.g., linemen) when the cyber 

security recovery plan is executed. The plan should 

include both traditional and modernized parts of the 

grid.

Improvements

RC.IM-1 RC.IM-1 RC.IM-1 RC.IM-1 Incorporating lessons-learned into plans is absolutely 

critical for maintaining reliability and resilience. In this 

case the other two business goals are of secondary 

importance.

RC.IM-2 RC.IM-2 RC.IM-2 RC.IM-2 Updating recovery strategies is critical for reliability and 

resilience and should cover any activities relevant to 

safety and grid modernization.

Communications

RC.CO-1 RC.CO-1 RC.CO-1 RC.CO-1 While important, managing public relations is not critical 

for the four goals.

RC.CO-2 RC.CO-2 RC.CO-2 RC.CO-2 While important, repairing reputation is not critical for 

the four goals.

RC.CO-3 RC.CO-3 RC.CO-3 RC.CO-3 Cyber security event recovery activities have to be 

coordinated to ensure safety of power system owner

operator workers (e.g., linemen) working on power 

recovery. Recovery efforts also require coordination 

across power systems, some of which may be 

modernized and some not.

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This publication is available free of charge from: https://doi.org/10.6028/NIST.SP.XXX This DRAFT report is provided for public comment, and is available from: https://www.nist.gov/el/smart-grid/smart-grid-framework

Appendix H – Logical Interface Categories from NISTIR 7628

Table 21 – Logical Interface Categories from NISTIR 7628 [126]

Logical Interface Category Logical Interfaces 

1. Interface between control systems and equipment with high availability, and 

with compute and/or bandwidth constraints, for example: 

• Between transmission SCADA and substation equipment 

• Between distribution SCADA and high priority substation and pole-top 

equipment 

• Between SCADA and distributed control systems (DCS) within a power 

plant 

• (NOTE: LICs 1-4 are separate due to the architecturally significant 

differences between the availability and constraints, which impact 

mitigations such as encryption.) 

U67, U79, U81, U82, U85, 

U102, U117, U137 

2. Interface between control systems and equipment without high availability, 

but with compute and/or bandwidth constraints, for example: 

• Between distribution SCADA and lower priority pole-top equipment 

• Between pole-top IEDs and other pole-top IEDs 

U67, U79, U81, U82, U85, 

U102, U117, U137 

3. Interface between control systems and equipment with high availability, 

without compute nor bandwidth constraints, for example: 

• Between transmission SCADA and substation automation systems 

U67, U79, U81, U82, U85, 

U102, U117, U137 

4. Interface between control systems and equipment without high availability, 

without compute nor bandwidth constraints, for example: 

• Between distribution SCADA and backbone network-connected collector 

nodes for distribution pole-top IEDs 

U67, U79, U81, U82, U85, 

U102, U117, U137 

5. Interface between control systems within the same organization, for example: 

Multiple DMS systems belonging to the same utility 

• Between subsystems within DCS and ancillary control systems within a 

power plant 

U7, U9, U11, U13, U27, U65, 

U67, U83, U87, U115, Ux2 

6. Interface between control systems in different organizations, for example: 

• Between an RTO/ISO EMS and a utility energy management system 

U10, U56, U66, U70, U74, 

U80, U83, U87, U89, U90, 

U115, U116, Ux3 

7. Interface between back office systems under common management authority, 

for example: 

• Between a Customer Information System and a Meter Data Management 

System 

U2, U4, U21, U22, U26, U31, 

U53, U96, U98, U110, Ux4 

8. Interface between back office systems not under common management 

authority, for example: 

• Between a third-party billing system and a utility meter data management 

system 

U1, U4, U6, U15, U52, U53, 

Ux4, Ux6 
181

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Logical Interface Category Logical Interfaces 

9. Interface with B2B connections between systems usually involving financial 

or market transactions, for example: 

• Between a Retail aggregator and an Energy Clearinghouse 

U4, U9, U17, U20, U51, U52, 

U53, U55, U57, U58, U72, 

U90, U93, U97 

10. Interface between control systems and non-control/corporate systems, for 

example: 

• Between a Work Management System and a Geographic Information 

System 

U12, U30, U33, U36, U52, 

U59, U75, U91, U106, U113, 

U114, U131 

11. Interface between sensors and sensor networks for measuring environmental 

parameters, usually simple sensor devices with possibly analog measurements, 

for example: 

• Between a temperature sensor on a transformer and its receiver 

U111 

12. Interface between sensor networks and control systems, for example: 

• Between a sensor receiver and the substation master 

U108, U112 

13. Interface between systems that use the AMI network, for example: 

• Between MDMS and meters 

• Between LMS/DRMS and Customer EMS 

U2, U6, U7, U8, U21, U24, 

U25, U32, U95, U119, U130 

14. Interface between systems that use the AMI network with high availability, 

for example: 

• Between MDMS and meters 

• Between LMS/DRMS and Customer EMS 

• Between DMS Applications and Customer DER 

• Between DMS Applications and DA Field Equipment 

U2, U6, U7, U8, U21, U24, 

U25, U32, U95, U119, U130 

15. Interface between systems that use customer (residential, commercial, and 

industrial) site networks which include: 

• Between Customer EMS and Customer Appliances 

• Between Customer EMS and Customer DER 

• Between Energy Service Interface and PEV 

U42, U43, U44, U45, U49, 

U62, U120, U124, U126, U127 

16. Interface between external systems and the customer site, for example: 

• Between Third Party and HAN Gateway 

• Between ESP and DER 

• Between Customer and CIS Web site 

U18, U37, U38, U39, U40, 

U42, U88, U92, U125 

17. Interface between systems and mobile field crew laptops/equipment, for 

example: 

• Between field crews and GIS 

• Between field crews and substation equipment 

U14, U29, U34, U35, U99, 

U101, U104, U105 

18. Interface between metering equipment, for example: 

• Between sub-meter to meter 

• Between PEV meter and Energy Service Provider 

U24, U25, U41, U46, U47, 

U48, U50, U54, U60, U95, 

U128, U129, Ux5 
182

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Logical Interface Category Logical Interfaces 

19. Interface between operations decision support systems, for example: 

• Between WAMS and ISO/RTO 

U77, U78 

20. Interface between engineering/maintenance systems and control equipment, 

for example: 

• Between engineering and substation relaying equipment for relay settings 

• Between engineering and pole-top equipment for maintenance 

• Within power plants 

U109, U114, U135, U136, 

U137 

21. Interface between control systems and their vendors for standard 

maintenance and service, for example: 

• Between SCADA system and its vendor 

U5 

22. Interface between security/network/system management consoles and all 

networks and systems, for example: 

• Between a security console and network routers, firewalls, computer 

systems, and network nodes 

U133 (includes interfaces to 

actors 17-Geographic

Information System, 12 –

Distribution Data Collector, 38 

– Customer Portal, 24 –

Customer Service 

Representative, 23 – Customer 

Information System, 21 – AMI 

Headend, 42 – Billing, 44 –

Third Party, 43 – Energy 

Service Provider, 41 –

Aggregator / Retail Energy 

Provider, 19 – Energy Market 

Clearinghouse, 34 – Metering / 

Billing / Utility Back Office) 
183

Appendix I – Types of Information Exchange Between Entities in the High-DER Example

Table 22 – Information exchanges in Figure 20 High-DER example

Interface Entity #1 Entity #2 Logical Interface 

Security 

Protection against Attacks Notification of 

Possible Attacks

Responding to and 

Coping with Attacks

Recovery from 

Attacks

Level 1: Autonomous Cyber-Physical Systems

D09 4a: DER 

Controller 

of DER 

Devices 

(single or 

in 

aggregate)

4b: DER 

Device or 

Unit (e.g. 

PV, 

Storage, 

Diesel, 

Turbine)

LIC #3: Interface 

between control 

systems and 

equipment with 

high availability, 

without compute 

nor bandwidth 

constraints

Communications between DER 

components and their DER 

controller typically uses 

ModBus. Cybersecurity 

protection of this protocol is not 

feasible, so physical security, 

such as locked rooms or cabinets 

should be used. If necessary, a 

VPN can be used to secure the 

transport of ModBus messages.

External means, such as 

Intrusion Detection 

Systems (IDS) and 

SNMP MIBs (IEC 

62351-7) would be used 

to notify of possible 

attacks

Responses to attacks 

may depend on the type 

and criticality of the 

DER, but most likely 

will require aborting 

communications. The 

DER may or may not 

continue to operate.

The controller and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.

D10 6a: EVSE 

Charging 

Stations

6a: EVSE 

Charging 

Stations

LIC #4: Interface 

between control 

systems and 

equipment 

without high 

availability, 

without compute 

nor bandwidth 

constraints

Most communications between 

EV Service Elements (charging 

stations) and EVs use the 

ISO/IEC 15118 standard, while 

the actual charging standards 

vary among different countries 

and for different levels (Levels 

1-3, fast charging) and types of 

charging (AC vs. DC charging). 

Cybersecurity for these standards 

are partially developed.

External means, such as 

Intrusion Detection 

Systems (IDS) and 

SNMP MIBs (IEC 

62351-7) would be used 

to notify of possible 

attacks

Responses to attacks 

would most likely 

require aborting 

communications. The 

EVSE may or may not 

continue to charge EVs, 

using local default 

charging functions.

The EVSE and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.
184

Interface Entity #1 Entity #2 Logical Interface 

Security 

Protection against Attacks Notification of 

Possible Attacks

Responding to and 

Coping with Attacks

Recovery from 

Attacks

D11 4c: UtilityScale DER 

System or 

Plant (e.g. 

large 

storage 

system)

4d: DER 

Device or 

Unit (e.g. 

PV, 

Storage, 

Diesel, 

Turbine)

LIC #3: Interface 

between control 

systems and 

equipment with 

high availability, 

without compute 

nor bandwidth 

constraints

Communications between DER 

components and their DER 

controller typically uses 

ModBus. Cybersecurity of this 

protocol is not feasible, so 

physical security, such as locked 

rooms or cabinets should be 

used. If necessary, a VPN can be 

used to secure the transport of 

ModBus messages.

External means, such as 

Intrusion Detection 

Systems (IDS) and 

SNMP MIBs (IEC 

62351-7) would be used 

to notify of possible 

attacks

Responses to attacks 

may depend on the type 

and criticality of the 

DER, but most likely 

will require aborting 

communications. The 

DER may or may not 

continue to operate.

The controller and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.

Level 2: Facilities DER Energy Management Systems (FDEMS)

U45 #5: Facility 

EMS (DER 

and Load) 

or Plant 

EMS

4a: DER 

Controller 

of DER 

Devices 

(single or 

in 

aggregate)

LIC #3: Interface 

between control 

systems and 

equipment with 

high availability, 

without compute 

nor bandwidth 

constraints

Communications between DERs 

and the Energy Management 

System within their facility 

could use many different 

protocols, including IEC 61850, 

IEEE 2030.5, and Modbus. 

Cybersecurity would be the 

responsibility of the facility, and 

could range from none to very 

sophisticated, depending upon 

the facility requirements.

External means, such as 

Intrusion Detection 

Systems (IDS) and 

SNMP MIBs (IEC 

62351-7) would be used 

to notify of possible 

attacks IEC 62351 

security for IEC 61850 

could also detect 

possible attacks.

Responses to attacks 

would most likely 

require aborting 

communications, then 

attempting to reestablish 

communications with 

new keys.

The systems and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.

U62 #5: EV 

Fleet EMS

6a: EVSE 

Charging 

Stations

LIC #4: Interface 

between control 

systems and 

equipment 

without high 

availability, 

without compute 

nor bandwidth 

constraints

Communications between 

EVSEs and the EV fleet Energy 

Management System could use 

many different protocols 

including IEC 61850, IEEE 

2030.5, and OCPP. 

Cybersecurity would be the 

responsibility of the facility, and 

could range from none to very 

sophisticated, depending upon 

the facility requirements.

External means, such as 

Intrusion Detection 

Systems (IDS) and 

SNMP MIBs (IEC 

62351-7) would be used 

to notify of possible 

attacks IEC 62351 

security for IEC 61850 

could also detect 

possible attacks.

Responses to attacks 

would most likely 

require aborting 

communications, then 

attempting to reestablish 

communications with 

new keys.

The systems and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.
185

Interface Entity #1 Entity #2 Logical Interface 

Security 

Protection against Attacks Notification of 

Possible Attacks

Responding to and 

Coping with Attacks

Recovery from 

Attacks

Level 3: Third Party, Aggregators

D92 #5: 

FDEMS

#41b: 

Aggregator

LIC#16: Interface 

between external 

systems and the 

customer site

Communications would most 

likely use the Internet with 

proprietary protocols established 

by the Retail Energy Provider. 

Cybersecurity would most likely 

be minimal or use traditional IT 

techniques typically used over 

the Internet.

Internet-based 

techniques would be 

used to detect and 

notify users about 

malware or other 

attacks

Responses to attacks 

would most likely 

require aborting 

communications, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.

U92 #5: 

FDEMS

#41a: 

Retail 

Energy 

Provider 

(REP)

LIC#16: Interface 

between external 

systems and the 

customer site

Communications would most 

likely use the Internet with 

proprietary protocols established 

by the Retail Energy Provider. 

Cybersecurity would most likely 

be minimal or use traditional IT 

techniques typically used over 

the Internet.

Internet-based 

techniques would be 

used to detect and 

notify users about 

malware or other 

attacks

Responses to attacks 

would most likely 

require aborting 

communications, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.
186

Interface Entity #1 Entity #2 Logical Interface 

Security 

Protection against Attacks Notification of 

Possible Attacks

Responding to and 

Coping with Attacks

Recovery from 

Attacks

Level 4: Utility Operations

D01 #25: 

DERMS

#17: GIS LIC#5: Interface 

between control 

systems within 

the same 

organization

Communications would most 

likely use proprietary protocols 

or IEC 61968/70 (Common 

Information Model, CIM) and be 

protected within an electronic 

security perimeter. Cybersecurity 

authentication and authorization 

would reflect the organization’s 

policies.

Electronic security 

perimeter techniques 

would be used to detect 

intrusions, while rolebased access control 

(RBAC) techniques 

would be used to notify 

users of unauthorized 

interactions.

Responses to attacks 

would most likely 

require aborting 

communications, assess 

the electronic security 

perimeter, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules, including any 

electronic security 

perimeter routers, 

gateways, etc., would 

be tested for malware 

and additional measures 

for preventing attacks 

would be added.

D02 #27: DMS #25: 

DERMS

LIC#5: Interface 

between control 

systems within 

the same 

organization

Communications would most 

likely use proprietary protocols 

or IEC 61968/70 (CIM) and be 

protected within an electronic 

security perimeter. Cybersecurity 

authentication and authorization 

would reflect the organization’s 

policies.

Electronic security 

perimeter techniques 

would be used to detect 

intrusions, while RBAC 

techniques would be 

used to notify users of 

unauthorized 

interactions.

Responses to attacks 

would most likely 

require aborting 

communications, assess 

the electronic security 

perimeter, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules, including any 

electronic security 

perimeter routers, 

gateways, etc., would 

be tested for malware 

and additional measures 

for preventing attacks 

would be added.
187

Interface Entity #1 Entity #2 Logical Interface 

Security 

Protection against Attacks Notification of 

Possible Attacks

Responding to and 

Coping with Attacks

Recovery from 

Attacks

D03 #4c: Utility 

Scale DER 

or Plant

#29a: DER 

SCADA 

LIC#6: Interface 

between control 

systems in 

different 

organizations

Communications would most 

likely use ISO/RTO protocols 

such as IEEE 1815 (DNP3), IEC 

61850, or IEEE 2030.5 (SEP2). 

Cybersecurity authentication and 

authorization would use the 

security provided by those 

protocols and/or by establishing 

gateways to isolate interactions.

External means, such as 

Intrusion Detection 

Systems (IDS) and 

SNMP MIBs (IEC 

62351-7) would be used 

to notify of possible 

attacks; IEC 62351 

security for IEC 61850 

could also detect 

possible attacks.

Responses to attacks 

would most likely 

require aborting 

communications, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.

D04 #5: 

FDEMS

#29a: DER 

SCADA 

LIC#6: Interface 

between control 

systems in 

different 

organizations

Communications would most 

likely use ISO/RTO protocols 

such as IEEE 1815 (DNP3), IEC 

61850, or IEEE 2030.5 (SEP2). 

Cybersecurity authentication and 

authorization would use the 

security provided by those 

protocols and/or by establishing 

gateways to isolate interactions.

External means, such as 

Intrusion Detection 

Systems (IDS) and 

SNMP MIBs (IEC 

62351-7) would be used 

to notify of possible 

attacks; IEC 62351 

security for IEC 61850 

could also detect 

possible attacks.

Responses to attacks 

would most likely 

require aborting 

communications, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.

D05 #5: 

FDEMS

#25: 

DERMS

LIC#6: Interface 

between control 

systems in 

different 

organizations

Communications would most 

likely use ISO/RTO protocols 

such as IEEE 1815 (DNP3), IEC 

61850, or IEEE 2030.5 (SEP2). 

Cybersecurity authentication and 

authorization would use the 

security provided by those 

protocols and/or by establishing 

gateways to isolate interactions.

External means, such as

Intrusion Detection 

Systems (IDS) and 

SNMP MIBs (IEC 

62351-7) would be used 

to notify of possible 

attacks; IEC 62351 

security for IEC 61850 

could also detect 

possible attacks.

Responses to attacks 

would most likely 

require aborting 

communications, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.
188

Interface Entity #1 Entity #2 Logical Interface 

Security 

Protection against Attacks Notification of 

Possible Attacks

Responding to and 

Coping with Attacks

Recovery from 

Attacks

D07 #31: 

ISO/RTO 

Operations

#25: 

DERMS

LIC#6: Interface 

between control 

systems in 

different 

organizations

Communications would most 

likely use ISO/RTO protocols 

such as IEEE 1815 (DNP3), IEC 

61850, or IEEE 2030.5 (SEP2). 

Cybersecurity authentication and 

authorization would use the 

security provided by those 

protocols and/or by establishing 

gateways to isolate interactions.

External means, such as 

Intrusion Detection 

Systems (IDS) and 

SNMP MIBs (IEC 

62351-7) would be used 

to notify of possible 

attacks; IEC 62351 

security for IEC 61850 

could also detect 

possible attacks.

Responses to attacks 

would most likely 

require aborting 

communications, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.

D08 41b: 

Aggregator

#25: 

DERMS

LIC#6: Interface 

between control 

systems in 

different 

organizations

Communications would most 

likely use ISO/RTO protocols 

such as IEEE 1815 (DNP3), IEC 

61850, or IEEE 2030.5 (SEP2). 

Cybersecurity authentication and 

authorization would use the 

security provided by those 

protocols and/or by establishing 

gateways to isolate interactions.

External means, such as 

Intrusion Detection 

Systems (IDS) and 

SNMP MIBs (IEC 

62351-7) would be used 

to notify of possible 

attacks IEC 62351 

security for IEC 61850 

could also detect 

possible attacks.

Responses to attacks 

would most likely 

require aborting 

communications, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.

D91 #41b: 

Aggregator

#30: 

Energy 

Management 

System

LIC#10: Interface 

between control 

systems and noncontrol/corporate 

systems.

Communications would most 

likely use the Internet with 

proprietary or CIM-based 

protocols. Cybersecurity would 

most likely use traditional IT 

confidentiality techniques 

typically used over the Internet.

Internet-based 

techniques would be 

used to detect and 

notify users about 

malware or other 

attacks

Responses to attacks 

would most likely 

require aborting 

communications, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.
189

Interface Entity #1 Entity #2 Logical Interface 

Security 

Protection against Attacks Notification of 

Possible Attacks

Responding to and 

Coping with Attacks

Recovery from 

Attacks

U09 #29a: DER 

SCADA 

#27: DMS LIC#5: Interface 

between control 

systems within 

the same 

organization

Communications would most 

likely use proprietary protocols 

or IEC 61968/70 (CIM) and be 

protected within an electronic

security perimeter. Cybersecurity 

authentication and authorization 

would reflect the organization’s 

policies.

Electronic security 

perimeter techniques 

would be used to detect 

intrusions, while RBAC 

techniques would be 

used to notify users of 

unauthorized 

interactions.

Responses to attacks 

would most likely 

require aborting 

communications, assess 

the electronic security 

perimeter, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules, including any 

electronic security 

perimeter routers, 

gateways, etc., would 

be tested for malware 

and additional measures 

for preventing attacks 

would be added.

U11 #32: Load 

Manageme

nt

#27: DMS LIC#5: Interface 

between control 

systems within 

the same 

organization

Communications would most 

likely use proprietary protocols 

or IEC 61968/70 (CIM) and be 

protected within an electronic 

security perimeter. Cybersecurity 

authentication and authorization 

would reflect the organization’s 

policies.

Electronic security 

perimeter techniques 

would be used to detect 

intrusions, while RBAC 

techniques would be 

used to notify users of 

unauthorized 

interactions.

Responses to attacks 

would most likely 

require aborting 

communications, assess 

the electronic security 

perimeter, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules, including any 

electronic security 

perimeter routers, 

gateways, etc., would 

be tested for malware 

and additional measures 

for preventing attacks 

would be added.

U27 #27: DMS #36: OMS LIC#10: Interface 

between control 

systems and noncontrol/corporate 

systems

Communications would most 

likely use the Internet with 

proprietary or CIM-based 

protocols. Cybersecurity would 

most likely use traditional IT 

confidentiality techniques 

typically used over the Internet.

Internet-based 

techniques would be 

used to detect and 

notify users about 

malware or other 

attacks

Responses to attacks 

would most likely 

require aborting 

communications, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.
190

Interface Entity #1 Entity #2 Logical Interface 

Security 

Protection against Attacks Notification of 

Possible Attacks

Responding to and 

Coping with Attacks

Recovery from 

Attacks

U52 #41b: 

Aggregator

#31: 

ISO/RTO 

Operations

LIC#10: Interface 

between control 

systems and noncontrol/corporate 

systems.

Communications would most 

likely use the Internet with 

proprietary or CIM-based 

protocols. Cybersecurity would 

most likely use traditional IT 

confidentiality techniques 

typically used over the Internet.

Internet-based 

techniques would be 

used to detect and 

notify users about 

malware or other 

attacks

Responses to attacks 

would most likely 

require aborting 

communications, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.

U56 #29a: DER 

SCADA

#31: 

ISO/RTO 

Operations

LIC#6: Interface 

between control 

systems in 

different 

organizations

Communications would most 

likely use ISO/RTO protocols 

such as IEEE 1815 (DNP3), IEC 

61850, or IEEE 2030.5 (SEP2). 

Cybersecurity authentication and 

authorization would use the 

security provided by those 

protocols and/or by establishing 

gateways to isolate interactions.

External means, such as 

Intrusion Detection 

Systems (IDS) and 

SNMP MIBs (IEC 

62351-7) would be used 

to notify of possible 

attacks; IEC 62351 

security for IEC 61850 

could also detect 

possible attacks.

Responses to attacks 

would most likely 

require aborting 

communications, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.

U65 #29a: DER 

SCADA 

#25: 

DERMS

LIC#5: Interface 

between control 

systems within 

the same 

organization

Communications would most 

likely use proprietary protocols 

or IEC 61968/70 (CIM) and be 

protected within an electronic 

security perimeter. Cybersecurity 

authentication and authorization 

would reflect the organization’s 

policies.

Electronic security 

perimeter techniques 

would be used to detect 

intrusions, while RBAC 

techniques would be 

used to notify users of 

unauthorized 

interactions.

Responses to attacks 

would most likely 

require aborting 

communications, assess 

the electronic security 

perimeter, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules, including any 

electronic security 

perimeter routers, 

gateways, etc., would 

be tested for malware 

and additional measures 

for preventing attacks 

would be added.
191

Interface Entity #1 Entity #2 Logical Interface 

Security 

Protection against Attacks Notification of 

Possible Attacks

Responding to and 

Coping with Attacks

Recovery from 

Attacks

U87 #27: DMS #30: EMS LIC#6: Interface 

between control 

systems in 

different 

organizations

Communications would most 

likely use ISO/RTO protocols 

such as IEEE 1815 (DNP3), IEC 

61850, or IEEE 2030.5 (SEP2). 

Cybersecurity authentication and 

authorization would use the 

security provided by those 

protocols and/or by establishing 

gateways to isolate interactions.

External means, such as 

Intrusion Detection 

Systems (IDS) and 

SNMP MIBs (IEC 

62351-7) would be used 

to notify of possible 

attacks; IEC 62351 

security for IEC 61850 

could also detect 

possible attacks.

Responses to attacks 

would most likely 

require aborting 

communications, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.

U91 #41a: 

Retail 

Energy 

Provider 

(REP)

#30: 

Energy 

Management 

System

LIC#10: Interface 

between control 

systems and noncontrol/corporate 

systems.

Communications would most 

likely use the Internet with 

proprietary or CIM-based 

protocols. Cybersecurity would 

most likely use traditional IT 

confidentiality techniques 

typically used over the Internet.

Internet-based 

techniques would be 

used to detect and 

notify users about 

malware or other 

attacks

Responses to attacks 

would most likely 

require aborting 

communications, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.

U102 #27: DMS #17: GIS LIC#5: Interface 

between control 

systems within 

the same 

organization

Communications would most 

likely use proprietary protocols 

or IEC 61968/70 (CIM) and be 

protected within an electronic 

security perimeter. Cybersecurity 

authentication and authorization 

would reflect the organization’s 

policies.

Electronic security 

perimeter techniques 

would be used to detect 

intrusions, while RBAC 

techniques would be 

used to notify users of 

unauthorized 

interactions.

Responses to attacks 

would most likely 

require aborting 

communications, assess 

the electronic security 

perimeter, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules, including any 

electronic security 

perimeter routers, 

gateways, etc., would 

be tested for malware 

and additional measures 

for preventing attacks 

would be added.
192

Interface Entity #1 Entity #2 Logical Interface 

Security 

Protection against Attacks Notification of 

Possible Attacks

Responding to and 

Coping with Attacks

Recovery from 

Attacks

U106 #5: 

FDEMS

#32: Load 

Manageme

nt System

LIC#6: Interface 

between control 

systems in 

different 

organizations

Communications would most 

likely use ISO/RTO protocols 

such as IEEE 1815 (DNP3), IEC 

61850, or IEEE 2030.5 (SEP2). 

Cybersecurity authentication and 

authorization would use the 

security provided by those 

protocols and/or by establishing 

gateways to isolate interactions.

External means, such as 

Intrusion Detection 

Systems (IDS) and 

SNMP MIBs (IEC 

62351-7) would be used 

to notify of possible 

attacks; IEC 62351 

security for IEC 61850 

could also detect 

possible attacks.

Responses to attacks 

would most likely 

require aborting 

communications, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.

Level 5: Market Operations

D06 #19: 

Energy 

Market 

Clearingho

use

#25: 

DERMS

LIC#9: Interface 

with B2B 

connections 

between systems 

usually involving 

financial or 

market 

transactions

Communications would most 

likely use the Internet with 

proprietary or CIM-based 

protocols. Cybersecurity would 

most likely use traditional IT 

confidentiality techniques 

typically used over the Internet.

Internet-based 

techniques would be 

used to detect and 

notify users about 

malware or other 

attacks

Responses to attacks 

would most likely 

require aborting 

communications, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.

D20 #41b: 

Aggregator

#19: 

Energy 

Market 

Clearinghouse

LIC#9: Interface 

with business-tobusiness (B2B) 

connections 

between systems 

usually involving 

financial or 

market 

transactions

Communications would most 

likely use the Internet with 

proprietary protocols. 

Cybersecurity would most likely 

use traditional IT confidentiality 

techniques typically used over 

the Internet.

Internet-based 

techniques would be 

used to detect and 

notify users about 

malware or other 

attacks

Responses to attacks 

would most likely 

require aborting 

communications, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.
193

Interface Entity #1 Entity #2 Logical Interface 

Security 

Protection against Attacks Notification of 

Possible Attacks

Responding to and 

Coping with Attacks

Recovery from 

Attacks

U17 #20: 

Wholesale 

Market

#19: 

Energy 

Market 

Clearingho

use

LIC#9: Interface 

with B2B 

connections 

between systems 

usually involving 

financial or 

market 

transactions

Communications would most 

likely use the Internet with 

proprietary or CIM-based 

protocols. Cybersecurity would 

most likely use traditional IT 

confidentiality techniques 

typically used over the Internet.

Internet-based 

techniques would be 

used to detect and 

notify users about 

malware or other 

attacks

Responses to attacks 

would most likely 

require aborting 

communications, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.

U20 #41a:

Retail 

Energy 

Provider 

(REP)

#19: 

Energy 

Market 

Clearinghouse

LIC#9: Interface 

with business-tobusiness (B2B) 

connections 

between systems 

usually involving 

financial or 

market 

transactions

Communications would most 

likely use the Internet with 

proprietary protocols. 

Cybersecurity would most likely 

use traditional IT confidentiality 

techniques typically used over 

the Internet.

Internet-based 

techniques would be 

used to detect and 

notify users about 

malware or other 

attacks

Responses to attacks 

would most likely 

require aborting 

communications, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.

U58 #31: 

ISO/RTO 

Operations

#19: 

Energy 

Market 

Clearingho

use

LIC#9: Interface 

with B2B 

connections 

between systems 

usually involving 

financial or 

market 

transactions

Communications would most 

likely use the Internet with 

proprietary or CIM-based 

protocols. Cybersecurity would 

most likely use traditional IT 

confidentiality techniques 

typically used over the Internet.

Internet-based 

techniques would be 

used to detect and 

notify users about 

malware or other 

attacks

Responses to attacks 

would most likely 

require aborting 

communications, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.
194

Interface Entity #1 Entity #2 Logical Interface 

Security 

Protection against Attacks Notification of 

Possible Attacks

Responding to and 

Coping with Attacks

Recovery from 

Attacks

U93 #41a: 

Retail 

Energy 

Provider 

(REP)

#20: 

Wholesale 

Market

LIC#9. Interface 

with B2B 

connections 

between systems 

usually involving 

financial or 

market 

transactions

Communications would most 

likely use the Internet with 

proprietary protocols established 

by the Retail Energy Provider. 

Cybersecurity would most likely 

use traditional IT confidentiality 

techniques typically used over 

the Internet.

Internet-based 

techniques would be 

used to detect and 

notify users about 

malware or other 

attacks

Responses to attacks 

would most likely 

require aborting 

communications, then 

attempting to reestablish 

communications with 

new keys. If malware 

was detected, systems 

would require their 

removal.

The systems and any 

communication 

modules would be 

tested for malware and 

additional measures for 

preventing attacks 

would be added.
195

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1 Appendix J – List of Reviewed Smart Grid Interoperability Standards

2

3 The NIST Review of Smart Grid Standards for Testing and Certification Landscape Analysis 

4 [60] evaluated 240 standards drawn from multiple sources that are relevant to the smart grid. 

5 Of those 240 standards, NIST’s functional categorization approach indicated 169 were 

6 relevant to interoperability. Each of the 169 standards deemed relevant to interoperability 

7 were assessed for the existence — or plan for — a testing and certification (T&C) program. 

8

9 The 169 interoperability relevant standards are listed in Table 23. Included within this table 

10 are the functional categories used to identify standards as interoperability-relevant. Also 

11 included is the NIST assessment of T&C availability for each standard.

12

13 T&C programs in Table 23 are categorized as follows:

14 x – an independent T&C authority (ITCA) exists for this standard

15 y – the ITCA program for this standard derives from requirements established in a 

16 different standard

z – 1st or 2nd 17 party T&C programs exist for this standard

18 p – a T&C program is planned for this standard

19

20 This table is graphically depicted in Figure 24.

21

22 The full paper and methodology for this analysis, with detailed descriptions of each of the 

23 240 standards reviewed, can be downloaded via this link: 

24 https://doi.org/10.6028/NIST.TN.2042

25

26

27 Table 23 – List of standards reviewed for testing and certification availability

Standard No.

Information 

Model

Communication 

Physical 

Performance

Communication 

Mapping

Model

Mapping

T&C

ANSI C12.1-2008 x z

ANSI C12.1-2014 x z

ANSI C12.18-2006 x x x

ANSI C12.19-2008 x

ANSI C12.19-2012 x

ANSI C12.20-2015 x z

ANSI C12.21-2006 x x

ANSI C12.22-2012 x x
196

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Standard No.

Information 

Model

Communication 

Physical 

Performance

Communication 

Mapping

Model

Mapping

T&C

ANSI/ASHRAE 135-2016

(ISO 16484-5:2017)

xxy

ANSI/ASHRAE/NEMA 201-2016

(ISO 17800:2017)

x

ANSI/CEA 709.1-D-2014

(ISO/IEC 14908-1:2012)

x

ANSI/CEA 709.2-A-2006

(ISO/IEC 14908-2:2012)

x

ANSI/CEA 709.3-R2004

(ISO/IEC 14908-3:2012)

x

ANSI/CEA 709.4-2013xx

ANSI/CEA 852-C-2014x

ANSI/CEA 852.1-A-2014x

CTA 2045 x

IEC 60255x

IEC 60255-1:2009 x

IEC 60255-24:2013xx

IEC 60255-26:2013 x

IEC 60870-5-101:2003xx

IEC 60870-5-102:1996x

IEC 60870-5-103:1997x

IEC 60870-5-104 Ed. 2.1 b:2016 xx

IEC 60870-6-503:2014xx

IEC 60870-6-702:2014xx

IEC 60870-6-802:2014xx

IEC 61000-2-

2:2002+AMD1:2017+AMD2:2018

x

IEC 61000-3-2:2018x

IEC 61000-4-30:2015 x

IEC 61334-4-32:1996x

IEC 61334-4-41:1996x

IEC 61334-4-511:2000x

IEC 61334-4-512:2001x
197

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Standard No.

Information 

Model

Communication 

Physical 

Performance

Communication 

Mapping

Model

Mapping

T&C

IEC 61334-5-1:2001x

IEC 61850-5:2013 xx

IEC 61850-6:2009+AMD1:2018xy

IEC 61850-7-1:2011xxy

IEC 61850-7-2:2010xxy

IEC 61850-7-3:2010xy

IEC 61850-7-4:2010(E)xy

IEC 61850-7-410:2012+AMD1:2015x

IEC 61850-7-420:2009x

IEC 61850-7-500:2017 x

IEC 61850-7-510:2012 x

IEC 61850-8-1:2011xxy

IEC 61850-8-2:2018xx

IEC 61850-90-1: 2010 x

IEC 61850-90-10:2017 x

IEC 61850-90-8:2016 x

IEC 61850-9-2:2004 xxy

IEC 61850-9-2:2004 LExxy

IEC 61850-9-2:2011xy

IEC 61850-9-3:2016xxp

IEC 61850-80-1:2016 xx

IEC 61850-80-3:2015 xx

IEC 61850-80-4:2016 xx

IEC 61850-90-2:2016 xx

IEC 61850-90-3:2016 x

IEC 61850-90-5:2012xxxx

IEC 61850-90-7:2013 x

IEC 61850-90-17:2017 x

IEC 61851-1:2017x

IEC 61851-23:2014 xy
198

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Standard No.

Information 

Model

Communication 

Physical 

Performance

Communication 

Mapping

Model

Mapping

T&C

IEC 61851-24:2014xx

IEC 61869-9:2016xz

IEC 61968-4:2007 xz

IEC 61968-8:2015x

IEC 61968-9:2013x

IEC 61968-11: 2013xp

IEC 61968-13:2008 xp

IEC 61968-100:2013x

IEC 61970-301:2016xp

IEC 61970-401:2005 x

IEC 61970-501:2006 x

IEC 62053-21:2003+AMD1:2016xz

IEC 62053-22:2016xz

IEC 62053-23xz

IEC 62054-21 xz

IEC 62056-3-1:2013x

IEC 62056-4-7:2015xx

IEC 62056-5-3:2017xx

IEC 62056-6-1:2017xx

IEC 62056-6-2:2017xxx

IEC 62056-6-9:2016xxx

IEC 62056-7-3:2017 xx

IEC 62056-7-5:2016xx

IEC 62056-7-6:2013 xx

IEC 62056-8-20:2016 xx

IEC 62056-8-3:2013 xx

IEC 62056-8-5:2017 xx

IEC 62056-8-6:2017 xx

IEC 62056-9-1:2016 xx

IEC 62056-9-7:2013 x
199

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Standard No.

Information 

Model

Communication 

Physical 

Performance

Communication 

Mapping

Model

Mapping

T&C

IEC 62056-42:2002x

IEC 62056-46:2002x

IEC 62282-2:2012 x

IEC 62325-301:2014x

IEC 62325-351:2016x

IEC 62325-451:2017x

IEC 62325-503:2014x

IEC 62357-200:2015 xx

IEC 62541-3:2015 x

IEC 62541-4:2015 x

IEC 62541-5:2015 x

IEC 62541-6 :2015 x

IEC 62541-8:2015 xx

IEC 62541-9:2015 xx

IEC 62541-10:2015 x

IEC 62541-13:2015 x

IEC 62541-100:2015xx

IEC 62689-2:2016 x

IEC 62689-100:2016xx

IEEE 1377-2012

(ANSI C12.19)

x

IEEE 1451.0-2007xx

IEEE 1451.1-1999x

IEEE 1451.4-2004x

IEEE 1451.5-2007x

IEEE 1547-2018xy

IEEE 1547.3-2007xx

IEEE 1588-2008xxz

IEEE 1701-2011

(ANSI C12.18)

xx
200

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Standard No.

Information 

Model

Communication 

Physical 

Performance

Communication 

Mapping

Model

Mapping

T&C

IEEE 1702-2011

(ANSI C12.21)

xx

IEEE 1815-2010xxz

IEEE 1815-2012xxz

IEEE 1815.1-2015/Cor1-2016xxxx

IEEE 1901-2010x

IEEE 1901.2-2013/IEEE Std 1901.2a-2015 

(Amendment to IEEE Std 1901.2-2013)

x

IEEE 2030-2011 x

IEEE 2030.5-2013xxz

IEEE 2030.7-2017xx

IEEE C37.118.1-2011x

IEEE C37.118.1a-2014xx

IEEE C37.118.2-2011x

IEEE C37.238-2011xx

IEEE C37.238-2017 xxp

IEEE C37.239-2010x

IETF RFC-6272-2011x

ISO 15118-2:2014x

ISO 15118-3:2015x

ISO 15118-6x

ISO 15118-8:2018x

ISO/IEC 14908-1:2012x

ISO/IEC 14908-2:2012x

ISO/IEC 14908-4:2012x

ISO/IEC 15067.3:2012xx

ITU T-G.9903x

ITU T-G.9960-2011x

ITU T-G.9972:2010x

MultiSpeak Security-V1.0xxx

MultiSpeak V3.0:2015xxx
201

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Standard No.

Information 

Model

Communication 

Physical 

Performance

Communication 

Mapping

Model

Mapping

T&C

NAESB REQ.21xxx

NAESB RMQ.18x

NAESB RMQ.26 xxp

NAESB WEQ.19:2010x

NEMA SG-AMI 1-2009 (R2015)xz

NISTIR 7761-2011x

NISTIR 7862-2012x

NISTIR 7943-2013xx

OASIS EMIX V1.0:2012x

OASIS EI-2014 V1.0xx

OASIS WS Calendar V1.0x

OPC-UAxxxxz

OGC-GMLxx

OpenADR 2.0 Profile A

OpenADR 2.0 Profile B

xxx

SAE J1772-2017xx

SAE J2836-Use-Cases-(1-3)

SAE J2836/1

x

SAE J2847/1:2010x

1
202

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