Metrics

A. Customer / AMI Metrics

1. Number of advanced meter malfunctions where customer electric service is disrupted, and the percentage this number represents of the total of installed advanced meters.

Policy Goal Supported: To measure improvements in grid reliability at the customer level and to measure the ability of the smart grid to avoid and identify outages. § 8360(a).

Definitions:

Advanced Meter: A meter that measures interval data and enables two-way communication between utilities and the meters located at customer premises.

Includes Advanced Meters, or smart meters approved by the CPUC under the Advanced Metering Infrastructure deployment programs.

Excludes RTEM and legacy meters (electro-mechanical and non-AMI).

Percentage: Percentage is defined as [(the number of advanced meter malfunctions where customer service is disrupted) divided by (the number of advanced meters installed)], with the resulting number multiplied by 100.

Meter Malfunction: Malfunction that caused an Advanced Meter to become inoperable. If a meter included a tamper detection feature, then the reporting should report separately meter malfunctions due to tampering from other malfunctions.

Includes Advanced Meters with integrated service switch.

Excludes Advanced Meters without service switch, RTEM, and legacy meters.

Service Disruption: Outages caused by faulty Advanced Meters.

Excludes outages caused by service panel or weather head issues or house fires, outages caused by Advanced Meters without service switch, RTEM or legacy meters, Advanced Meters installed with service switch open by mistake, and Advanced Meter replacements.

Applicable Data Sources Already Reported:

SDG&E: Smart Meter Program Quarterly Reports

PG&E: Not currently reported

SCE: Not currently reported

Reporting Start Date: July 2011 through AMI deployment completion date (IOUs expect meter malfunctions that disrupt electric service to be insignificant upon completion of AMI deployment)

Comments: Includes only Advanced Meter malfunctions that result in loss of power, which may be insignificant and not relevant to overall effectiveness of Advanced Meter performance for purposes of energy and outage management, especially following completion of deployment.

Does not include malfunctions that do not result in service disruptions (e.g., usage measurement malfunctions).

2. Load impact in MW of peak load reduction from the summer peak and from winter peak due to smart grid-enabled, utility administered demand response (DR) programs (in total and by customer class).

Policy Goal Supported: To measure the achievement of energy efficiency and demand response goals as listed in § 454.5 and § 454.55 -- § 8366(d)

Definitions:

Smart Grid-Enabled Demand Response Programs: Demand Response programs that rely upon two-way communications, including Advanced Meters that allow for Home Area Network or internet enabled access of interval meter data and/or notifications

Includes: PTR (CARE and non-CARE Demand Response (DR) impacts, to the extent available), CPP, PCT, TOU, A/C Cycling,

Excludes: Energy information tools such as In-Home Displays, web presentment, budget assistant, and third-party data access.

Load Impact: Demand Response MW reductions will be determined, measured by ex post load impact analysis, coincident with each utility's system peak (adjusted to account for the Demand Response load reduction).

Customer Class: A group of customers with similar characteristics that have similar rate schedules or structures for electric service. For the purposes of this metric, customer classes shall be defined by existing tariff structures. For each utility, the customer classes shall be as follows:

for SCE: (1) Residential, (2) C&I < 200 kW, (3) C&I ≥ 200 kW, (4) Agriculture and Pumping.

for PG&E: (1) Residential, (2) non-Residential < 200 kW, (3) non-Residential ≥ 200 kW, (4) Other.

for SDG&E: (1) Residential, (2) C&I < 500 kW, (3) C&I ≥ 500 kW, (4) Other.

Applicable Data Sources Already Reported:

PG&E and SCE: AMI Annual Energy Savings Report

PG&E, SCE, and SDG&E: Annual demand response load impact reports

Reporting Start Date: July 2011

Comments: This metric will not measure achievement of energy efficiency goals or energy conservation.

3. Percentage of demand response enabled by AutoDR (Automated Demand Response) in each individual DR impact program.

Policy Goal Supported: The smart grid seeks to promote the use of demand response and is tied to § 8366(d) and § 8360(d).

Definitions:

AutoDR: Demand Response that is enabled through a variety of technologies that are automatically activated upon receiving a Demand Response event or price trigger from the Demand Response provider. Examples of technologies include energy management systems and software, wired and wireless controls, thermostats and enabled appliances. For purposes of this metric, AutoDR is limited to utility administered programs for business customers.

Percentage: Verified kW load reductions (engineering analysis) available for Demand Response, divided by total Demand Response portfolio kW, with the resulting number multiplied by 100.

Enabled: Event triggered Demand Response programs

Applicable Data Sources Already Reported: Annual Load Impact Report

Reporting Start Date: July 2011

Comments: None

4. The number and percentage of utility-owned advanced meters with consumer devices with Home Area Network (HAN) or comparable consumer energy monitoring or measurement devices registered with the utility (by customer class, CARE status, and climate zone).

Policy Goal Supported: Some of the benefits of the smart grid are linked to customer usage of its capabilities, and this metric seeks to measure customer use of smart grid and advanced meter capabilities. Tied to § 8360(f), (h) (i) and § 8366(a).

Definitions:

Consumer Devices: Smart grid-enabled tools used by consumers that communicate with the utility-owned Advanced Meter or other gateway.

Includes Home Area Network devices (e.g., In-Home Displays, Programmable Communicating Thermostats, PC USB devices); devices owned by the consumer, utility or third-party; devices that are included as part of a utility program; devices that are not included in part of a utility program.

Excludes PC-software applications, internet portal applications (e.g., bill forecast, bill-to-date, SCE's budget assistant tool, PG&E/SDG&E's tier alerts, presentment of interval data), plug-in electric vehicles (PEV), energy efficiency (EE) and solar-related devices, and A/C cycling devices.

Percentage: Percentage is defined as [(the number of advanced meters with consumer devices with HAN or comparable consumer energy devices registered with the utility) divided by (the number of advanced meters installed for the group of concern)], with the resulting number multiplied by 100.

Register: The act or process of pairing a consumer device to a Home Area Network. Used to ensure that devices are communicating with the intended recipient (e.g., Advanced Meter). Registering a device is a control to prevent cyber-security and privacy issues.

Considerations:

· All devices that communicate with the utility's Home Area Network will need to be registered with the utility, regardless of where or how the device was purchased, or the ownership of such device. In addition, all devices that are part of a utility program will need to be registered with the utility.

· This metric is likely a cumulative metric and will therefore increase over time. That is, once an Advanced Meter has a device registered to it, the customer is unlikely to de-register the device, even if the device is no longer in use.

Customer Class: A group of customers with similar characteristics that have similar rate schedules or structures for electric service. For the purposes of this metric, customer classes shall be defined by existing tariff structures. For each utility, customer classes shall be:

for SCE: (1) Residential, (2) C&I < 200 kW, (3) C&I≥200 kW, (4) Agriculture and Pumping.

for PG&E: (1) Residential, (2) non-Residential < 200 kW, (3) non-Residential≥200 kW, (4) Other.

for SDG&E: (1) Residential, (2) C&I < 500 kW, (3) C&I≥500 kW, (4) Other.

CARE: California Alternate Rates for Energy (CARE) program. CARE offers income-qualified customers a discount of 20% or more off their monthly electric bill.

Climate Zone: An area that is distinguished by its climate so that utility customers within the territory have similar heating and cooling needs.

Applicable Data Sources Already Reported: None.

Reporting Start Date: Dependent on wide commercial availability of utility Home Area Network and comparable consumer devices, which is expected no earlier than 2012 to 2013.

Comments: Widespread availability of Consumer Device capabilities have been delayed due to a delay in the adoption of the Smart Energy Profile 2.0 HAN national standard and uncertainty regarding commercial availability beyond that date. Pursuant to D. 11-07-056, the IOUs were required to file a HAN Implementation Plan by November 29, 2011. Those plans are currently under review by the Commission. D.11-07-056 envisioned a plan to allow up to 5,000 customer-owned Customer Devices to be able to connect their Advanced Meters. The IOUs plans allow for limited roll-out using SEP 1.0/1.X. IOUs expect widespread availability of Consumer Devices using the SEP 2.0 standard may become available in the 2013 to 2014 timeframe or later. Thus, this metric will be relevant and reported as part of future smart grid Annual Reports.

This metric will only include devices that are registered with the utility's Advanced Meter. Devices that connect with a different gateway are excluded. Also, devices that are connected to an energy management system, but not registered with the utility, are excluded (even though the energy management system may be registered with the utility).

A commissioned or enrolled device will be a subset of the registered devices.

Utilities will be registering¹²⁴ devices, which involves authentication and authorizing a HAN device to exchange secure information with the HAN. However, utilities will not be commissioning¹²⁵ devices, as commissioning a device allows for an exchange of a limited amount of information, but may not provide appropriate cyber-security protections. Program enrollments¹²⁶are provided in Customer/AMI Metric 2 "Load impact in MW of peak load reduction from summer peak and from winter peak due to smart grid-enabled, utility administered demand response (DR) programs (in total and by customer class)," and Customer/AMI Metric 5 "Number and percentage of customers that are on a time-variant or dynamic pricing tariff (by type of tariff, by customer class, by CARE status, and by climate zone)."

SCE does not currently have the capability to track devices by CARE/non-CARE and climate zone. SCE would need to add this functionality to its data warehouse system in order to provide this data.

5. Number and percentage of customers that are on a time-variant or dynamic pricing tariff (by type of tariff, by customer class, by CARE status, and by climate zone).

Definitions:

Time Variant or Dynamic Pricing Tariff: A rate in which prices can be adjusted on short notice (typically an hour or day ahead) as a function of system conditions. A dynamic rate cannot be fully predetermined at the time the tariff goes into effect; either the price or the timing is unknown until real-time system conditions warrant a price adjustment.

Includes customers on CPP, TOU, RTP rates, customers enrolled in PTR notifications, and customers on separately metered PEV rates.

Excludes A/C cycling programs, PCT programs, and customers with a PEV that are not on an EV time variant rate.

Percentage: Percentage is defined as [(the number of customers that are on a time-variant or dynamic pricing tariff) divided by (the number of customers in the group of concern)], with the resulting number multiplied by 100.

for SCE: (1) Residential, (2) C&I < 200 kW, (3) C&I≥200 kW, (4) Agriculture and Pumping.

for PG&E: (1) Residential, (2) non-Residential < 200 kW, (3) non-Residential≥200 kW, (4) Other.

for SDG&E: (1) Residential, (2) C&I < 500 kW, (3) C&I≥500 kW, (4) Other.

CARE: Number of customers enrolled in the California Alternate Rates for Energy (CARE) program. CARE offers income-qualified customers a discount of 20% or more off their monthly electric bill.

Climate Zone: An area that is distinguished by its climate so that utility customers within the territory have similar heating and cooling needs.

Applicable Data Sources Already Reported:

PG&E, SCE, SDG&E-Monthly DR reports

PG&E and SCE-AMI Annual Energy Savings Reports

Reporting Start Date: July 2011

Comments: Excludes customers currently enrolled in TOU, CPP, and RTP tariffs; that is, customers enrolled in dynamic tariffs pre-AMI are excluded.

6. Number and percentage of escalated customer complaints related to (1) the accuracy, functioning, or installation of advanced meters or (2) the functioning of a utility-administered Home Area Network with registered consumer devices.

Policy Goal Supported: Linked to cost-effectiveness and provision of information to customers. § 8360(a) (e) (h).

Definitions:

Escalated Complaint: A complaint (written or telephonic) received by the utility's Consumer Affairs Department (or equivalent) regarding the Advanced Meter or program, or regarding device registration and communication issues.

Percentage: Percentage is defined as [(the number of escalated complaints related to (1) the accuracy, functioning, or installation of advanced meters or (2) the functioning of a utility-administered Home Area Network with registered consumer devices) divided by (the number of escalated complaints in total)], with the resulting number multiplied by 100.

Advanced Meter: A meter that measures interval data and enables two-way communication between utilities and the meters located at customer premises.

Includes Advanced Meters, or smart meters approved by the CPUC under the Advanced Metering Infrastructure deployment programs.

Excludes RTEM and legacy meters (electro-mechanical and non-AMI).

Consumer Device: Smart grid-enabled tools used by consumers that communicate with the utility-owned Advanced Meter or other gateway.

Excludes devices not registered with the utility and devices communicating with HANs provided by non-utilities.

Home Area Network: A network of energy management devices, digital consumer electronics, signal-controlled or enabled appliances, and applications within a home environment that is on the home side of the electric meter.

Includes HANs provided by a utility.

Excludes HAN provided by non-utilities (e.g., customers, device manufacturers).

Considerations:

Complaints related to the interaction of consumer devices with HANs, is dependent on the availability of utility HAN consumer devices, which is expected at a later date.

Applicable Data Sources Already Reported:

SDG&E: Smart Meter Program Quarterly Reports

SCE: Not currently reported

PG&E: Partial current reporting

Reporting Start Date: July 2011 for complaints related to Advanced Meters. 2013/2014 for complaints related to the interaction of consumer devices with HANs.

Comments: Complaints should include only Escalated Complaints received regarding the functioning or accuracy of Advanced Meters. This metric may also be combined with Customer/AMI Metric 9 and include all Escalated Complaints regarding the interaction of consumer devices with utility-administered HANs.

Includes only escalated complaints. For SCE, these are complaints received by the Consumer Affairs department.

This metric will include all escalated complaints related to consumer devices, including those complaints that were determined to be caused by the consumer device and not the utility HAN.

Metric to be reported by complaint type: AMI meters, AMI programs, device registration, and communication issues.

7. The number and percentage of advanced meters replaced before the end of their expected useful life during the course of one year, reported annually, with an explanation for the replacement.

Policy Goal Supported: Linked to cost-effectiveness and provision of information to customers (§ 8360(a) (e) (h)).

Definitions:

Advanced Meter: A meter that measures interval data and enables two-way communication between utilities and the meters located at customer premises.

Includes Advanced Meters, or smart meters approved by the CPUC under the Advanced Metering Infrastructure deployment programs.

Excludes RTEM and legacy meters (electro-mechanical and non-AMI).

Percentage: Percentage is defined as [(the number of advanced meters replaced before the end of their expected useful life during the course of one year, reported annually) divided by (the number of advanced meters installed)], with that resulting number multiplied by 100.

Replaced: Advanced Meter that is replaced due to a malfunction causing the Advanced Meter to become inoperable.

Applicable Data Sources Already Reported: None

Reporting Start Date: July 2011

Comments: Possible reasons for meter replacement: meter malfunction, meter installation error, or customer tampering.

8. Number and percentage of advanced meters field tested at the request of customers pursuant to utility tariffs providing for such field tests, and the number of advanced meters tested measuring usage outside the Commission-mandated accuracy bands.

Policy Goal Supported: Linked to cost-effectiveness and provision of information to customers (§ 8360(a) (e) (h)).

and the number of advanced meters tested

measuring usage outside of the Commission-mandated accuracy

bands.

Definitions:

Advanced Meter: A meter that measures interval data and enables two-way communication between utilities and the meters located at customer premises.

Includes Advanced Meters, or smart meters approved by the CPUC under the Advanced Metering Infrastructure deployment programs.

Excludes RTEM meters, legacy meters, and Advanced Meters replaced when service panel is removed or upgraded, installed in wrong service type, or customer changes rate (NEM,) requiring a new meter with a different program.

Percentage: Percentage is defined as [(the number of advanced meters field tested) divided by (the number of advanced meters installed)], with that resulting number multiplied by 100.

Field Test: A test requested by a customer and conducted personnel at the customers premise to determine if a meter is measuring usage correctly.

Includes customer-requested field tests performed by utilities.

Excludes tests independently conducted (not customer-requested).

Applicable Data Sources Already Reported: None

Reporting Start Date: July 2011

Comments: Per current tariff rules, utilities will perform one field test every six months at no charge at the customer's request. This metric does not include field test requests that are not performed by utilities.

9. Number and percentage of customers using a utility web-based portal to access energy usage information or to enroll in utility energy information programs or who have authorized the utility to provide a third-party with energy usage data.

Policy Goal Supported: Linked to cost-effectiveness and provision of information to customers (§ 8360(a) (e) (h)).

Definitions:

Customers: Number of unique customers that (1) have interval usage data available to them, and (2) have accessed the energy usage information at least once during the preceding 12 months.

Internet or Other Web-Based Portal:

Includes mobile phone applications

Excludes customers accessing energy usage information from non-utility portals or websites

Enrollments in Energy Information Programs:

Includes enrollments in Tier Alert / Budget Assistant programs, phone applications

Excludes enrollments in dynamic pricing and customers calls

Energy Usage Information:

Includes interval usage data collected by the Advanced Meter, backhauled to utility back office systems, and presented on utility web sites.

Excludes usage or other data presented on third-party websites or tools, near real-time usage data available or any other information that is not received /stored in the utility back office systems (i.e., information received directly from the HAN), and cumulative energy usage information.

Applicable Data Sources Already Reported: None

Reporting Start Date: July 2011

Comments: Metric should measure unique customers using web based tools and other energy information programs available that will not require customers to access the Web. Examples of these programs include Tier Alert (PG&E and SDG&E) and Budget Assistant (SCE) programs.

This metric excludes customers accessing usage information through non-utility-authorized portals, and also excludes customer accessing cumulative usage information.

B. Plug-in Electric Vehicle Metrics

1. Number of customers enrolled in time-variant electric vehicles tariffs

Policy Goal Supported: Provides a view into the usage of plug in electric vehicles; consistent with § 8362(g).

Definitions:

Time Variant Electric Vehicle Tariffs:

1) for SCE: TOU-EV-1, TOU-EV-2, TOU-EV-3, TOU-EV-4, and TOU-D-TEV;

2) for PG&E: E9a and E9b;

3) for SDG&E: EV-TOU, EV-TOU-2, EV-TOU-3, EPEV-X, EPEV-Y and EPEV-Z.

Applicable Data Sources Already Reported: None

Reporting Start Date: July 2011

Comments: Utilities currently have limited ability to determine which customers have electric vehicles. As methods for acquiring this information are determined in that proceeding, this metric should be updated.

Metrics related to metering arrangements should be deferred until after PEV metering policy is set in Alternative Fueled Vehicles OIR (R.09-08-009).

C. Storage Metrics

1. MW and MWh per year of utility-owned or operated energy storage interconnected at the transmission or distribution system level. As measured at the storage device electricity output terminals.

Policy Goal Supported: Determine the number of units providing storage services to the network and their capability; § 8362(g).

Definitions: None

Applicable Data Sources Already Reported: None

Reporting Start Date: July 2011

Comments: Utilities may not have access to information about energy storage systems owned by independent power producers or customer-sited and owned systems.

D. Grid Operations Metrics

1. The system-wide total number of minutes per year of sustained outage per customer served as reflected by the System Average Interruption Duration Index (SAIDI), Major Events Included and Excluded for each year starting on July 1, 2011 through the latest year that this information is available.

Policy Goal Supported: Meet reporting requirements of § 8366(e) and the policy goal of § 8360(a).

Definitions:

IOUs will use information reported in Annual Reliability Reports to produced information required for this metric. Each IOU's Annual Reliability Report is available at: http://www.cpuc.ca.gov/PUC/energy/ElectricSR/Reliability/annualreports/.

Applicable Data Sources Already Reported: Annual Reliability Reports

Reporting Start Date: July 2011

Comments: Location and circuit- level information is too detailed and variable over time to be included in metrics. Utilities have as many as 4,500 circuits.

Consideration should be given to creating new metrics aimed at providing circuit-level information.

2. How often the system-wide average customer was interrupted in the reporting year as reflected by the System Average Interruption Frequency Index (SAIFI), Major Events Included and Excluded for each year starting on July 1, 2011 through the latest year that this information is available.

Policy Goal Supported: Meet reporting requirements of § 8366(e) and the policy goal of § 8360(a).

Definitions:

Applicable Data Sources Already Reported: Annual Reliability Reports

Reporting Start Date: July 2011

Comments: Location and circuit-level information is too detailed and variable over time to be included in metrics. Utilities have as many as 4,500 circuits.

Consideration should be given to creating new metrics aimed at providing circuit-level information.

3. The number of momentary outages per customer system-wide per year as reflected by the Momentary Average Interruption Frequency Index (MAIFI), Major Events Included and Excluded for each year starting on July 1, 2011 through the latest year that this information is available.

Policy Goal Supported: Meet reporting requirements of § 8366(e) and the policy goal of § 8360(a)

Definitions:

Applicable Data Sources Already Reported: Annual Reliability Reports

Reporting Start Date: July 2011

Comments: Location- and circuit- level information is too detailed and variable over time to be included in metrics. Utilities have as many as 4,500 circuits.

Consideration should be given to creating new metrics aimed at providing circuit-level information.

4. Number and percentage of customers per year and circuits per year experiencing greater than 12 sustained outages for each year starting on July 1, 2011 through the latest year that this information is available.

Policy Goal Supported: Meet reporting requirements of § 8366(e) and the policy goal of § 8360(a)

Definitions:

Percentage of customers experiencing greater than 12 sustained outages per year equals [(the number of customers experiencing greater than 12 sustained outages in a year) divided by (the total number of customers)] with the resulting number multiplied by 100.

Percentage of circuits experiencing greater than 12 sustained outages per year equals [(the number of circuits experiencing greater than 12 sustained outages in a year) divided by (the total number of circuits)] with the resulting number multiplied by 100.

Applicable Data Sources Already Reported: Annual Reliability Reports

Reporting Start Date: July 2011

Comments: Location- and circuit- level information is too detailed and variable over time to be included in metrics. Utilities have as many as 4,500 circuits.

Consideration should be given to creating new metrics aimed at providing circuit-level information.

5. System load factor and load factor by customer class for each year starting on July 1, 2011 through the latest year that this information is available.

Policy Goal Supported: Meet reporting requirements of § 8366(e) and the policy goal of § 8360(a)

Definitions:

System: The distribution system owned and operated by a utility.

Load Factor: Calculated by dividing (1) average load (total energy divided by number of hours) during the year by (2) peak load during the year. In the case of Load Factor by customer class, the average and peak load during the year shall both be measured for that customer class (as opposed to the system).

for SCE: (1) Residential, (2) C&I < 200 kW, (3) C&I≥200 kW, (4) Agriculture and Pumping.

for PG&E: (1) Residential, (2) non-Residential < 200 kW, (3) non-Residential≥200 kW, (4) Other.

for SDG&E: (1) Residential, (2) C&I < 500 kW, (3) C&I≥500 kW, (4) Other.

Applicable Data Sources Already Reported: Calculations for this metric will be based on data collected for the purpose of Annual Rate Group Load Studies. Some statistics from the Load Studies are used for analyses in the Phase II (Rate Design) of a General Rate Case.

SCE's Annual Load Profiles are available at: http://www.sce.com/AboutSCE/Regulatory/loadprofiles/

PG&E's Annual Load Profiles are available at: http://www.pge.com/nots/rates/instruction.shtml

SDG&E's Annual Load Profiles are available at: http://www2.sdge.com/eic/dlp/dynamic.cfm

Reporting Start Date: July 2011

Comments: Until Advanced Meters are fully deployed for residential, small commercial and industrial, and small agriculture customers, load factor will be calculated using estimates, rather than measured directly.

6. Number of and total nameplate capacity of customer-owned or operated, grid-connected distributed generation facilities.

Policy Goal Supported: State policy seeks to promote both distributed generation and the use of renewables. The ability to integrate these resources is an expected benefit of the smart grid. This is tied to § 8366 (b) renewable and § 8360(c) distributed generation.

Definitions:

Distributed Generation Facilities: Customer-owned or operated generating systems that are enrolled with a utility in the Self Generation Incentive Program (SGIP) or the California Solar Initiative (CSI) or otherwise operating under a Feed In Tariff (FIT).

Electricity Deliveries From Grid-Connected, Customer Owned Or Operated Distributed Generation: All electricity purchased by a utility under a Net Surplus Compensation Tariff or under a Feed In Tariff (FIT), measured in KWh.

Applicable Data Sources Already Reported: SGIP, CSI and FIT reports.

Reporting Start Date: July 2011

Comments: Use programs and tariffs to define "distributed generation."

Information and estimates about production of distributed generation facilities that serve on-site customer load is produced annually by the CEC in their California Energy Demand Forecast

7. Total electricity deliveries from customer-owned or operated, grid-connected distributed generation facilities, reported by month and my ISO sub-Load Aggregation Point.

Definitions:

Distributed Generation Facilities: Generating systems that are (1) enrolled with a utility in the Self Generation Incentive Program (SGIP) or the California Solar Initiative (CSI) (2) part of each utility's respective Solar PV program or, (3) operating under a Feed In Tariff (FIT).

Applicable Data Sources Already Reported: SGIP, CSI and FIT reports.

Reporting Start Date: July 2011

Comments: Use programs and tariffs to define "distributed generation."

Information and estimates about production of distributed generation facilities that serve on-site customer load is produced annually by the CEC in their California Energy Demand Forecast

8. Number and percentage of distribution circuits equipped with automation or remote control equipment, including Supervisory Control and Data Acquisition (SCADA) systems.

Policy Goal Supported: Measure the extension/development of the smart grid.

Definitions

Percentage of distribution circuits equipped with automation or remote control equipment equals [(the number of distribution circuits equipped with automation or remote control equipment) divided by (the total number of distribution circuits)] with the resulting number multiplied by 100.

Applicable Data Sources Already Reported: None

Reporting Start Date: July 2011

Comments: All IOUs track SCADA installation while there are significant interpretation challenges associated with both automation equipment and total load associated with either SCADA or automation or control equipment.

(END OF ATTACHMENT A)

ATTACHMENT B

Initial Set of Cyber-Security Questions

What are utilities currently reporting to other agencies (cyber-security, privacy and breach notification)? What is a utility's obligation to report breaches or violations to the public or individuals?

What other groups/associations do utilities report cyber-security incidents to, i.e., other utilities, contractors, etc.?

How many cyber-security attacks does a utility average during a day/week/month/year?

How many cyber-security attacks result in an escalated response, or require additional action to repel?

How many security breaches have resulted in the dissemination of personal/customer information?

How often does a utility engage with an independent third-party to engage in penetration testing of their networks, such as AMI, operations, other mainframes, etc.?

How often does a utility engage with an independent third-party to perform a security audit?

How does a utility define a cyber attack, a security break, etc.?

What criteria does a utility use to determine the competence of an internal and/or third-party penetration tester and/or auditors?

What do utilities do when they have determined that Smart Grid components/systems/equipment are vulnerable to security breaches?

Who is responsible for the costs of fixing security breaches due to vulnerabilities in products?

What known security vulnerabilities in the Smart Grid deployment currently remain in a vulnerable state?

What cryptographic techniques/methods are used by utilities to protect the systems?

What automated testing tools/security software are used by the utilities to protect the systems

Do utilities require security certifications for the purchased systems/components?

Do utilities have permanent job positions for security/cryptography professionals?

Do utilities have mechanisms in place to check against publicly known security vulnerabilities?

Do utilities have mechanisms to automatically apply security patches?

(END OF ATTACHMENT B)

¹²⁴ Registration is defined as "The process by which a Commissioned HAN device is authorized to communicate on a logical network. This involves the exchange of security credentials... The registration process is required for the exchange of secure information..." Definition per the , Draft v1.95, Open HAN Task Force, and referred to in NISTIR 7628 Guidelines for Smart Grid Cyber Security, Vol. 2, Privacy and the Smart Grid, issued in August 2010.

¹²⁵ Commissioning is defined as "The process by which a HAN device obtains access to a specific physical network and allows the device to be discovered on that network." Admission to the network allows the HAN device to communicate with peer devices and receive public broadcast information, but the information is not secured.

¹²⁶ Enrollment is defined as "The process by which a Consumer enrolls a HAN device in a Service Provider's program (e.g. demand response, energy management, pre-pay, PEV programs, distributed generation programs, pricing, messaging, etc.) and gives certain rights to the Service Provider to communicate with their HAN device."