Overview of PG&E’s DER and Smart Grid Activities Enabling Customer Options and California’s Clean Energy Future

Grid Integration & Innovation Team February 3, 2017

2

Agenda

• Safety & Introductions (9:00am - 9:10am)

• Overview of CA Policy Landscape (9:10am - 9:45am)

• Integration of DERs and Smart Grid Activities (9:45am - 10:45am) Operational

Technologies (inc. EV program, rates, and PG&E vehicles providing distribution services)

• PG&E Smart Grid/DER Pilots (10:45am-11:30am)

• Q&A/Discussion (11:30am-12:00pm)

3

Company Facts Fortune 200 company located in San Francisco, CA

$16.8B in operating revenues in 2015

Over 20,000 employees

Energy Supply Services to 16M people:

• 5.4M Electric accounts

• 4.3M Natural Gas accounts

Peak electricity demand: Approx. 21,000 MW

Approx. 60% of PG&E’s electric supply comes from

non-greenhouse gas emitting facilities

Service Territory 70,000 sq. miles with diverse topography

160,000 circuit miles of electric trans. and dist. lines

49,000 miles of natural gas trans. and dist. pipelines

Pacific Gas & Electric Company (PG&E)

Source: http://www.pge.com/en/about/company/profile/index.page , CEC California Energy Demand Forecast 2014-2024 Preliminary Forecast and PG&E 2015 10-K filing

4

Focus on Sustainability

4

PG&E U.S. Avg

RPS GHG Free

58%

32%

Nearly 2x More Carbon Free and Renewable

Energy Than The U.S. Average in 2015

Sustainability Advisory Council established in 2015

PG&E Customers Lead the Nation in

Clean Technology Adoption

~800 GWh/yr of efficiency savings Ranked #2 among U.S. utilities

>280,000 solar customers Ranked #1 with ~25% of all U.S. rooftop solar

Nearly 100,000 electric vehicles Ranked #1 with ~20% of all U.S. vehicles

Extensive Third Party Recognition

5

0

100

200

300

400

500

600

2000 2005 2010

California’s Climate Goals

5

California is Targeting:

50% renewables by 2030

1.5M electric vehicles by 2025

2X energy efficiency in existing buildings by 2030

California Greenhouse Gas Reduction Goals

and Historic Emissions*

Million metric tons CO2e

PG&E is a critical partner in achieving California’s clean energy goals

*Source: California Air Resources Board

2020 2030 2015 2025

AB 32 requires

California to return to

1990 levels by 2020

SB 32 requires at

least 40% below 1990

levels by 2030

Historic Emissions

Ag. & Forestry

Res. & Comm.

Transportation

Electricity

Generation

Industrial

Data Sources: PG&E’s 2002 Corporate Environmental Report, and PG&E’s 2015 10-K. PG&E 2020 forecast is based on PG&E’s 2014 RPS Compliance report filing.

2015

30% of total sales 2002

11% of total bundled retail

sales

2020

37% of total sales

PG&E’s Renewable Portfolio Progress

Almost 60% of the power supplied by PG&E in 2015 came from

renewable or carbon-free sources

6

• PG&E has 280,000+ solar customers,

more than any other U.S. utility – adding

6,000 new solar customers each month –

with industry-leading interconnection speed

• Customer energy generation is treated

primarily as a demand-side resource

• PG&E is actively managing implications

Integrating into investment and resource

planning

Modernizing/managing grid for two-way power

flow, voltage/power quality, and grid resiliency

Balancing system load with intermittent

renewable energy generation sources

Providing alternate customer service offerings

Engaging in solar policy and rate reform

Rooftop Solar is Growing Rapidly

0

500

1,000

1,500

2,000

2,500

MW

Non Residential Residential

Cumulative Retail Solar PV Capacity

34% CAGR

PG&E has 25% of all U.S. rooftop PV installations

and continues to support our customers who want to “go solar”

• Programs and Tariffs

• Customer Experience

• Policy Development

Lead the nation by offering a suite of innovative DG

programs and services

Anticipate changes in the DG market and proactively

shape the DG policy

Trusted Energy Advisor - Be our customers’ best

source for trustworthy information on DG options

DG Programs DG Tariffs

• Self-Generation Incentive Program (SGIP)

• Net Energy Metering-NEM • NEM Aggregation

• California Solar Initiative Thermal Program (CSIT)

• Virtual Net Metering

• Multi-Family Affordable Solar Housing

• Renewable Energy Self-Gen Bill Credit Transfer

• California Solar Initiative PV Program - closed

• NEMEXMP, NEMMT, Option R

Distributed Generation Programs

SGIP Program Technologies Offered

Revisions from D.16-06-055; “Current” as of 2016, “Adopted” as of 2017

SGIP Program Budget; 2017-2020

Category 2016 New Program 2017 - 2020

PG&E SGIP Budget $33.48M Double the budget &

CSI-style steps

Approx. $285M excluding

admin funds

Renewable & Emerging

Technologies (75%) $25.11M

Change to AES,

receiving 75% of

budget

~$214M

Non-Renewable Fueled

Conventional CHP Projects

(25%)

$8.37M

Change to Gen

receiving 25% of

budget

~$71M

Administration $2.52M No change ~$10M

*Before program opening in 2017, the 2017-2020 budget will be summed, split into the AES & Gen buckets

(75/25), and then split into 5 AES and 3 Gen incentive steps with carve-outs for 15% Resi AES and 40%

Renewable Generation.

11 11

Managing Evolution of Energy Landscape

Flexible Electric Portfolio

Utility-Owned Generation

~45%

Procured ~55%

Constructive Regulatory Mechanisms

Revenues decoupled from sales

Cost allocation mechanisms for

departing customers

Modernizing Rate Structures Focus on Continuous Improvement

Residential

Rate Design

Time of Use

Rates

Fixed/

Demand

Charges

Net Energy

Metering

CPUC Distributed Energy Resources Action Plan

Procurement

Efficiencies

Leveraging

Technology

Process Standardization

Sustainable Efficiencies

• Expand System Monitoring • Test and deploy new sensing and communication

technologies

• Develop and utilize sophisticated system modeling and forecasting

• Dynamic and Localized Control • Build communication and control systems to

mitigate any grid instability

• Test and deploy controls to capture potential grid value from DERs and other customer solutions

• Simple & Standard Integration • Strengthen the core system in preparation for

expanded DER penetration

• Develop and deploy standardized interconnection and ensure easy customer participation

The increase in distributed energy resources (DERs) leads to increased grid complexity

Significant investment in the grid is needed to address this complexity

The Grid is a Vital Component to a Reliable Energy Future & for Further PV Enablement

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Integration of DERs and Smart Grid Activities

Objectives of Renewable Integration

Maintain current safety and reliability

Maximize the amount of interconnected renewable resources to meet GHG goals

Minimize interconnection and system upgrade costs

Lower energy costs to customers

Enhance System power quality and reliability

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Power System Operation

Requirements

Existing system capabilities and

limitations

Regulatory Requirements

(Rule 2)

Renewable gen characteristics

& output profiles

Load characteristics

& profiles

Mitigation Measures

State Policy

Economics

Considerations for Renewable Integration

Solutions

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DG must coordinate with various devices on a typical PG&E circuit.

Protection Devices Devices in RED such as breakers, reclosers, and fuses must be coordinated with DG protection

schemes, including anti-islanding, taking into account the additional fault contributions from DG.

Voltage Regulation Devices in GREEN are voltage devices that must be re-coordinated to account for DG flow

Most PGE feeders have voltage regulated by a substation Load Tap Changer and many have multiple capacitors and tap changing regulators

Conductors A portion of the feeder is considered “main line” where conductors are large

Tap lines are used to further distribute power and connect customers

Line transformers are used to step power down to secondary voltage to serve multi customers

Most of the lines are economically sized for the load that they are serving

SUB

R F F F

F

Typical Distribution Circuit Design

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Challenges System designed to serve load and regulate voltage radially, from a single source, with progressively

smaller conductors to ensure affordability.

Most of the distribution conductors are small and susceptible to large voltage fluctuations due to moderate power flow

System is regulated to +/- 5% of nominal voltage to provide proper steady state voltage automatically from zero to full load to distribution customer equipment.

System not designed for bi-directional flow associated with generation.

PG&E limits the voltage fluctuations by relying on load diversity and limiting the largest single load that can be operated at a given time.

Utility Responsibilities Maintain Safety of the power grid and the public

Maintain existing service reliability and power quality

Maintain Voltage and Frequency to all load customers within proper limits

Ensure existing power system equipment will not be overloaded

Existing System Design Challenges

SUB

R F F F

F

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DG Voltage Concerns

114 V

126 V

Acceptable

voltage band

With DG (PV)

Without DG (PV)

Feeder

Acceptable

Service

Voltage Band

Electric

Rule 2

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Existing Requirements – Rule 21

Line Capacitor Line Regulator Substation LTC Customer

Load

Distributed

Generation

If the DG is operating within the existing distribution system design parameters, with no reverse flow, it has minimal system impact.

Rule identified low impact conditions and provided simplified requirements to allow small DG units at low penetration levels to be interconnected quickly as long as safety issues are addressed.

Typically, there are sufficient existing design & operating margin to accommodate the small DG units when they trip off-line. Some over-trip of the DG is deemed tolerable at the local level.

This significantly simplified the review & approval process and reduced the interconnect review time for the small units.

Typically, the small NEM PV units < than 30 kW can be approved and interconnected in < than 10 Working Days.

1. Majority of the existing inverters designed for lo penetration, grid interactive mode, set at unity power

factor and certified not to operate when the grid is de-energized (certified anti-islanding)

2. Grid interactive inverters produce the maximum available energy and rely on the grid for voltage and

frequency support, as well as back-up service when the DGs are not generating.

3. Some inverters are designed for stand-alone operation and have the capability to follow load and

regulate voltage after they are isolated from the gird. But schemes are more customized, costly and

complex; requiring further review.

Line Capacitor Line Regulator Substation LTC Customer

Load

Distributed

Generation

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Today’s Planning Process

1. Forecast 5 Year Demand

2. Simulate to Identify Deficiencies

3. Develop Mitigations

1. Demand forecasting is performed for each feeder and bank using both regression and spatial forecasting algorithms with weather normalized peak KW and customer KWH consumption

2. One in 10 weather normalized peak load projections for each circuit is imported into the power flow CYME program to determine system adequacy. CYME incorporates historical PV through the load allocated using KWH consumption and other types of DG are added directly to each feeder model.

3. Mitigation options to address deficiencies are developed including system upgrades such as substation transformers, feeders, re-conductoring, voltage regulating devices and switching/load transfers. Non-wire options are also considered.

Preparing for the Future

Anticipated Changes At higher penetration, cumulative DG impacts are no longer negligible

Current interconnection requirements need to be revised (IEEE 1547, UL1741 and Rule 21)

Ride through capability needs to be expanded to avoid common mode failure

Smart inverter features are being expanded and certified

At high penetrations, there may be opportunities to realize DG benefits. DGs may need to be monitored and controlled by the distribution system operator (DSO).

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AC Grids • Load and generation on the grid must be dynamically balanced at all times.

1. Adjust generation output level, add reserve generation or curtail generation to match load (traditional set-up)

2. Adjust load level by shedding load, or insert load banks (used only during emergency conditions)

3. Grid utilization voltage and frequency and power system equipment maintained within limits

Microgrids • DGs designed and operated to be capable of both grid-interactive and islanded modes, and to

coordinate with other generators on the microgrid.

– Sufficient aggregate local generation capacity to supply specified load at all times. May require adding storage, or standby generators, to accommodate intermittency:

• load following and frequency regulation

• voltage regulation- the micro grid studied at all load/generation conditions to have proper voltage on the entire micro grid

• redundant generation for reliability

• load shedding

• separation from the main grid without tripping generation

• synchronization with the grid at the return of main grid

Power Systems Requirements

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At what local penetration level should utility start to actively consider microgrid operation? Simplified assumptions of 20% PV capacity factor and 40% load factor are used in the table below.

Based on the tabulation above, PV penetration below 50% may not yield significant benefit for microgrid operation since 75% of the load will need to be shed. But if the critical load is less than 25%, and/or a shorter duration support is acceptable, microgrid mode may be viable. The above simplified assessment did not take storage conversion losses into account, nor the need for potential larger storage inverters to carry the momentary motor loads.

What are the incremental benefits of microgrid operation and the associated costs to enable this mode of operation?

For feeder/area microgrids, which customer load should be tripped if there are insufficient renewable DG in the local area?

What is the proper mix between transmission and distribution connected renewable generation?

Emerging Issues and Questions

% PV Penetration Level % of daily load

energy supplied

% load that needs to be shed

to enable continuous

microgrid operation

50% 25% 75%

100% 50% 50%

200% 100% 0%

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1. Limit behind the meter installations to non-export

Allow the distribution system to operate with power flow in one direction and may significantly reduce the mitigation costs.

2. Connect larger installations to large mainline conductors close to substations.

3. Connect the large units with dedicated feeders to avoid causing voltage problems with other distribution customers.

4. Install batteries on larger PV installations and modify the inverter design to ramp power up and down gradually to minimize voltage flicker, as needed.

Allow the voltage regulators sufficient time to correct for voltage fluctuations due to sudden PV/wind output changes during cloud movements/wind gusts. Trade-off some increase in wear and tear on the existing voltage regulators.

5. Use smart inverters to control voltage within limits.

6. Use storage for load/generation peak shaving and short term UPS applications.

7. Design the PV to align the PV output closer to load peak.

8. For microgrid applications, consider using fuel-based generators, in addition to short term storage, for infrequent long outage support.

9. At high system-wide PV penetrations, use TOU rates to shift the load peak close to noon and minimize the need to deploy expensive batteries.

Enable a broader set of DG capabilities to fully utilize resources to support the grid.

Potential Mitigations to Reduce Cost

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PG&E and California are seeing strong EV adoption

1. EPRI, R.L. Polk Data, 2016

5,000-30,000

1,000-4,999

500-999

100-499

0-99

Cumulative EV Sales by County1

PG&E Service Area

110,000 EVs in PG&E service

area today

PG&E’s service area adds over 2,400 new EVs

each month. Adoption has been strongest

around the Bay Area.

5% of 2016 new vehicle sales in PG&E

service area were electric vehicles

-

30,000

60,000

90,000

120,000

-

1,000

2,000

3,000

4,000

2011 2012 2013 2014 2015 2016

Cu

mu

lati

ve E

V r

egi

stra

tio

ns

Mo

nth

ly E

V r

egi

stra

tio

ns

Plug-in hybrid electric vehicles Battery electric vehicles Cumulative Total

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PG&E offers special time-of-use rates for residential EV charging

Summer: $0.45

Winter: $0.31

Summer: $0.24

Winter: $0.19

Summer: $0.12

Winter: $0.12

Approx.

cost per

kWh

80% of EV charging occurs at home • Time of use rates encourage off-peak charging and lower fuel costs

Best for higher energy users (Tier 2 & 3), who can shift usage to overnight

Visit www.pge.com/myrateanalysis

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Utility infrastructure programs address key barrier to adoption

Summary of Approved Decision:

• Scope: 3-years, $130M budget

• Scale: Up to 7,500 level 2

chargers (approx. 500-750 sites)

• Sites: Multi-unit dwellings (MUDs)

and workplaces

Details:

• Minimum 15% of sites located in disadvantaged communities

• Site host choice of charging equipment and products from prequalified vendors

• Option to own chargers or sponsor PG&E-owned chargers in certain sectors

• Rolling procurement/qualification process

• Driver pricing & load management flexibility for site hosts

Timeline for implementation:

• Commission voted unanimously to approve decision on December 15th

• PG&E beginning program contracting and site host recruitment in early 2017.

• First site deployments expected Q4 2017

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Utility fleet vehicles for power export and distribution services

Project Objective:

• Develop vehicle technology and

demonstrate “vehicle on-site grid

support system” with utility-grade

power

• Use fleet vehicles to power distribution

circuit or independent load

• Increase reliability through avoiding

planned or unplanned outages

Use cases tested:

• Transformer replacement

• Power on demand (Events) and EV

charging

• Establish temporary microgrid

• Remote specialty equipment

transport and power

Benefits

Safety: support for emergency response, quieter

work environment for crews

Reliability: reduced outage impacts

Affordability: leverage vehicle fleet instead of

investment in generator sets

Societal: Reduced emissions and noise pollution

PG&E Smart Grid/DER Pilots

PG&E Electric Emerging Technology Programs

Smart Grid

Pilot Projects

Overview: Test and pilot Smart

Grid technologies to determine

the business case for larger

scale deployment

2013-2016 (~4 years)

Pilot Projects: 1. Smart Grid Line Sensors

2. Volt/VAR Power Optimization

3. Detect & Locate Outages and

Faulted Circuits

4. Short-term Demand Forecasting

EPIC Program (Electric Program Investment Charge)

Overview: Test and field trial new

automation, analytics, control and

measurement technologies to

meet priority utility objectives.

2014-2020 (6 years)

31 projects underway

Focus Areas: 1. Renewables and Distributed Energy

Resource Integration

2. Grid Modernization and Optimization

3. Customer Service and Enablement

4. Cross-cutting / Foundational

CES-21 (California Energy Systems

for the 21st Century)

Overview: Partnership with

Lawrence Livermore National

Laboratories (LLNL) and IOUs to

use advanced computational and

analytical capabilities for utility

challenges

2015-2017

(3 years, possible ext. to 2019)

Focus Areas:

1.Cybersecurity

2.Grid Integration

New research, development, and demonstration programs approved by the CPUC to bring

new technologies and new insights to support PG&E’s business priorities in the future

Research & Develop New Technologies Demonstrate Emerging Technologies Pilot Existing Technologies

The Technology: VVO

120V

126V

114V

• VVO advances CVR by using the power of computing and

communications to more tightly control voltage delivered to customers.

• Algorithmically-determined optimal line settings are implemented with

remote SCADA controls. This level of operational coordination would be

impossible if attempted manually.

• VVO has the potential to reduce power consumption by 1-2% with no

impact to consumers, while offering improved voltage control on

circuits with high DER (especially DG) penetration.

Line Capacitor Line Regulator Substation LTC Customer

Load

Distributed

Generation

Original

Voltage

Voltage

with

VVO

Standard Characteristics Top Capabilities of Certain Models

• Powered by line current • Easy to install

• Constant communications

• Real-time load and fault

values

• Electric sinusoidal waveform capture

• Electric indication of voltage levels

• Ability to detect current direction reversal

(useful for high DG environments)

The Technology: Line Sensors

• Traditional Faulted Circuit Indicators are “dumb” – they

turn on a light, providing a visual clue to field teams to

isolate a fault.

• Wireless Line Sensors are “smart” – they add

communications capability and provide sophisticated

data and sensing capabilities.

Characteristics of Modern Line Sensors

Traditional

Faulted

Circuit

Indicator

Line Sensors are remotely communicating devices that safely attach to

distribution wires, detect line current magnitude, and provide fault alerts.

The Technology: Calculated Fault Location

Using the knowledge of the

relationship between voltage,

current, and resistance, CFL

calculates the probable distance

from the substation to the fault.

Calculated Fault Location (CFL) is a mathematical method

of locating faults extrapolated from Ohm’s Law.

However, CFL is insufficient alone

because it can identify: • Too many possible fault locations because of

line branching

• Incorrect locations due to faulty

measurement data or system models

Too Many Results: All five are the

same distance from the substation

Layering Fault Location Approaches

CFL only Voltage Line Sensors “Layered View”

Filtered view shown

to operators

• In the example above left, all CFL-identified

locations are mathematically correct, but dispersed

and not helpful.

• The layered approach taken by the FDL project

reduced the area of potential fault location down to

the two orange highlighted areas at right. Actual fault

location

Solution Demonstrated: Layer data from CFL calculations, wireless line

sensors, and voltage data to narrow the results.

Enhance Decision Making

Enable Customers

Automate and Self

Heal

How PG&E is building the Grid of Things

Integrate Clean DERs

Move beyond accommodating DERs

to realizing the full resource value

Enhance decision making by gathering, analyzing, and visualizing new and expanding data streams to improve

operations, manage costs and support new services

Leverage technology to anticipate and respond to a more dynamic environment

Provide valuable services and products to further unlock benefits of the grid

Evolving four main capabilities to support a long term and sustainable business strategy, while continuing efforts to modernize existing grid assets

Landscape

• By 2025, millions of third party-owned DERs (ex. PV, battery storage, electric vehicles) are estimated to be interconnected to the

PG&E electric grid

• The DRP and other regulatory drivers are directing CA IOUs to enable behind-the-meter DERs to provide grid benefits

Demonstrating the Technology

• EPIC BTM Smart Inverters: demonstrate how Smart Inverters can be utilized to mitigate voltage issues that can be caused by

reverse power flow from solar PV to the grid

• EPIC BTM Energy Storage: demonstrate how aggregated BTM energy storage can be used to reduce electric load or absorb

distributed generation as needed

• EPIC DERMS: demonstrate how a centralized management system can control utility-owned and BTM DERs to realize utility and

customer benefits

• Smart Grid VVO: understand how smart inverters can work as optimization devices to manage voltages and save customers

money through conservation voltage reduction

PG&E DG Pilots – Background

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Detailed Overview of Pilots

# Pilot

Name Goal

How Does it Work /

Value Proposition

Customer

Enrollment

Target

Installation

Date

Target

Audience

Customer

Count

Target

Location

1

EPIC

BTM

Smart

Inverters

Demonstrate how

Smart Inverters can be

utilized to mitigate

voltage issues that can

be caused by reverse

power flow from solar

PV to the grid.

Voltage can spike, tripping solar

inverters and cascading to

transformers and other

equipment; communications can

protect grid by turning off the

inverter to not continue the

cascading voltage trip.

≈100

customers

(500kW)

Q3 2016

Res;

Commercial;

Industrial

Res ≈ 100

C&I ≈ 0 San Jose Div.:

Swift Bk 1

2

EPIC

BTM

Storage

Demonstrate

aggregated BTM

storage resources can

be used to reduce

electric load or absorb

distributed generation

as needed.

During peak usage periods,

loading on some utility

distribution feeders can

approach or exceed the rated

capacity of those feeders. BTM

storage can help with peak-load

reduction. Unexpected increase

in demand can be filled quickly

by battery storage.

40-70

customers

(0.5 MW;

4 MWh)

Late 2016/

Early 2017

Res: 30%

C&I: 70%

Res ≈ 30

C&I ≈ 20 San Jose Div.:

Swift Bk 1

3 EPIC

DERMS

Prove management

capabilities of DER

technology integration.

Two way communications

network between utility and DER

equipment.

Part of EPIC

projects

above

Late 2016/

Early 2017 - -

San Jose Div.:

Swift Bk 1

36

BTM Smart Inverters

Project Description: Deploy a 0.5 MVAR of Smart Inverters in San Jose (Grid of Things™ feeder) can be

utilized to mitigate voltage issues that can be caused by reverse power flow from solar PV to the grid. This

project will demonstrate various options to utilize customer-sited smart inverters (utility-controlled or

automated) vs. standard inverters to derive grid benefits.

Response to Abnormal Conditions

• L/HVRT-L/HFRT – Stay connected through short-term disturbances

• Anti-Islanding – Disconnect, prevent unintentional islanded operation during grid outage

• Reconnect and Ramp – Controlled reconnect and ramp following grid recovery

Active Power Control

• Limit Power Output – Limit maximum generation

• Volt-Watt – Adjust active power output based on grid voltage

• Ramp up/down rate – Provide gradual increase/decrease of power output when connecting/disconnecting

Reactive Power Supply

• Power Factor – Compensate for grid voltage rise/drop or reactive power demands

• Volt-VAr – Support grid voltage stabilization

Key functionalities tested:

37

BTM Smart Inverters

Customer Recruitment:

38

BTM Storage

Project Description: Deploy a 0.5 MW 4-hour Aggregated Energy Storage System (AESS) comprised of

multiple customer-sited Behind-The-Meter (BTM) battery storage systems to demonstrate load reduction (or

generation absorption) capability to support the distribution grid.

• RFO to procure storage services (assets are customer-owned or third-party-owned)

• Both residential and non-residential BTM storage tested

• No wholesale market component

M

Resiliency

Demand Charge Reduction

Solar TOU Arbitrage

Over-generation relief

Wholesale market participation (out of scope)

EPIC Project 2.19c Domain

Capacity

Status: Implementation phase (Identified location; issued RFO; selected vendors; starting customer outreach)

Completion: Q4 2017

Desired Outcome: Provide real-world operational information to the utility, regulators, and industry stakeholders

on the challenges and nuances of using BTM storage to provide grid services.

39

Key Project Objectives:

Deploy 0.5MW/4-hour aggregated BTM energy storage

Develop contractual agreements with vendors to ensure AESS is available to and can be directly called on during specified periods

Build capability to communicate via EPIC 2.2 DERMS with AESS for visualization and control

Provide an “apples-to-apples” comparison with EPIC 1.02 (Browns Valley), which is deploying an in-front-of-the-meter utility owned storage resource of similar size to defer a capacity upgrade

BTM Storage

Expected Outcomes:

Demonstrate whether customer-sited, utility-controlled AESS can effectively deliver distribution grid services

Assess the degree to which operational and cost-effectiveness is driven by utility-customer shared use/costs

Close existing knowledge gaps:

Real world testing of costs, contract terms, customer acquisition, and other programmatic unknowns

Real-world data on AESS performance, including ability of AESSs to provide grid services when needed

Means to visualize and control AESS resources

Swift 2102 feeder projected capacity constraint in

2020-2022

Feeder

Capacity

Projected

Load

40

Grid of Things Feeder™ Press Release (July 12 )

Recent PG&E announcement highlights collaboration between PG&E and GE, SolarCity and Enphase Energy to test deployment of Behind-the-Meter Smart Inverters (and Storage) to provide grid benefits.

Location and Customer Acquisition

Customer acquisition in targeted areas

• Up to three waves of customer outreach

• PG&E-Vendor co-branded material

• Vendor-led, PG&E-supported effort

Channels:

• email, field sales, calls

Communications:

• Press-release (Corp Comm)

• Coordination PG&E Contact Center and Vendor Contact Center

Closeout:

• Customer survey