Electric Schedule AG-4 - Jan 2015

8/10/2019 Electric Schedule AG-4 - Jan 2015

1/18

Revised Cal. P.U.C. Sheet No. 25909

Cancelling Revised Cal. P.U.C. Sheet No. 24930Pacific Gas and Electric CompanySan Francisco, CaliforniaU 39

ELECTRIC SCHEDULE AG-4 Sheet 1

TIME-OF-USE AGRICULTURAL POWER

(Continued)

Advice Letter No: 2948-E-A Issued by Date Filed January 18, 20

Decision No. 06-11-030 Brian K. Cherry Effective November 30, 20

Vice President Resolution No.

1C1 Regulatory Relations

1. APPLICABILITY: A customer will be served under this schedule if 70% or more of the annual energy useon the meter is for agricultural end-uses. Agricultural end-uses consist of:

(a) growing crops;

(b) raising livestock;

(c) pumping water for irrigation of crops; or

(d) other uses which involve production for sale.

Only agricultural end-uses performed prior to the First Sale of the agricultural productare agricultural end-uses under this criteria, except for the following activities, whichare also agricultural end-uses under this criteria: (a) packing and packaging of theagricultural products following the First Sale and before any subsequent sale, and

(b) agricultural end-uses by nonprofit cooperatives. Guidelines for interpreting thisapplicability statement are set forthwith in Section D of the Rule 1 DefinitionQualification for Agricultural Rates.

None of the above activities may process the agricultural product. Residentialdwelling, office, and retail usage are not agricultural end-uses.

The Rule 1 definition Qualification for Agricultural Rates specifies additional activitiesand meters that will also be served on agricultural rates, and guidelines through thefollowing sections: (B) Other Activities and Meters Also Served on Agricultural Rates,(C) Specific Applications of the March 2, 2006 Applicability Criteria, and (D) Guidelinesfor Applying the Applicability Criteria.

The provisions of Schedule SStandby Service Special Conditions 1 through 6 shallalso apply to customers whose premises are regularly supplied in part (but not inwhole) by electric energy from a nonutility source of supply. These customers will paymonthly reservation charges as specified under Section 1 of Schedule S, in addition toall applicable Schedule AG-4 charges. Exemptions to standby charges are outlined inthe Standby Applicability Section of this rate schedule.

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Advice Letter No: 3291-E Issued by Date Filed June 30, 20

Decision No. 07-09-004 Brian K. Cherry Effective July 30, 20


2C15 Regulatory Relations

1. APPLICABILITY:(Contd.)

Depending upon the end-use of electricity and whether or not a Time-Of-UseInstallation or Time-Of-Use Processing Charge applied prior to May 1, 2006, thecustomer will be served under one of the rates under Schedule AG-4: Rate A, B, C,D, E or F.

Rates A and D: Applies to single-motor installations with a connected loadrated less than 35 horsepower and to all multi-loadinstallations aggregating less than 15 horsepower or kilowatts.Rate D applies to customers who were on Rate D as of May1, 2006 and are not billed via SmartMeter. Rate A appliesto all other customers.

Rates B, C, E, and F: Applies to single-motor installations rated 35 horsepower ormore, to multi-load installations aggregating 15 horsepower orkilowatts or more, and to overloaded motors. The

customer's end-use is determined to be overloaded when themeasured input to any motor rated 15 horsepower or more isdetermined by PG&E to exceed one kilowatt per horsepowerof nameplate rated output. Rates E and F apply to customerswho were on Rates E and F as of May 1, 2006 and are notbilled via SmartMeter. Rates B and C apply to all othercustomers.

Rates B and C will apply to those customers whose maximum demand is 200 kW orgreater for three consecutive months and select this schedule upon the initialinstallation of the interval data meter, unless the customer was on Rate E or F as ofMay 1, 2006 and is not billed via SmartMeter.

The meters required for this schedule may become obsolete as a result of electricindustry restructuring or other action by the California Public Utilities Commission.Therefore, any and all risks of paying the required charges and not receivingcommensurate benefit are entirely that of the customer.

Ongoing daily Time-of-Use (TOU) meter charges applicable to customers takingvoluntary TOU service under this rate schedule will no longer be applied if thecustomer has a SmartMeter installed.

Transfers Off of Schedule AG-4: After being placed on this schedule due to the200 kW or greater provisions of this schedule, customers who fail to exceed199 kilowatts for 12 consecutive months may elect to stay on this schedule or elect anapplicable non-time-of-use rate schedule or alternate time-of-use rate schedule.

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3/18

Original Cal. P.U.C. Sheet No. 29106

Cancelling Cal. P.U.C. Sheet No.Pacific Gas and Electric CompanySan Francisco, CaliforniaU 39



(Continued)

Advice Letter No: 3631-E Issued by Date Filed March 11, 20

Decision No. 10-02-032 Jane K. Yura Effective May 1, 20


3C12 Regulation and Rates

1. APPLICABILITY:(Contd.)

Peak Day Pricing Default Rates: Peak Day Pricing (PDP) rates provide customersthe opportunity to manage their electric costs by reducing load during high cost periodsor shifting load from high cost periods to lower cost periods. Decision 10-02-032ordered that beginning February 1, 2011, eligible Agricultural customers default to PDPrates. A customer is eligible for default when 1) it has at least twelve (12) billing monthsof hourly usage data available, and 2) it has measured demands equal to or exceeding200 kW for three (3) consecutive months during the past 12 months. All eligiblecustomers will be placed on PDP rates unless they opt-out.

Customers that do not meet default eligibility may voluntarily elect to enroll on PDPrates.

Bundled service customers are eligible for PDP. Direct Access (DA) and CustomerChoice Aggregation (CCA) service customers are not eligible, including those DA

customers on transitional bundled service (TBS). Customers on standby service(Schedule S) and net-energy metering (NEM, NEMFC, NEMBIO, etc.) are not eligiblefor PDP.

For additional details and program specifics, see the Peak Day Pricing Details sectionbelow.

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Pacif ic Gas and Elect r ic Comp any

San Francisco, CaliforniaU 39

Revised Cal. P.U.C. Sheet No. 34661Cancelling Revised Cal. P.U.C. Sheet No. 34418

ELECTRIC SCHEDULE AG-4 Sheet 4TIME-OF-USE AGRICULTURAL POWER

(Continued)

Advice Letter No: 4484-E-A Issued by Date Filed December 31, 20Decision No. E-4693 Steven Malnight Effective January 1, 20 Senior Vice President Resolution No.4C8 Regulatory Affairs

2. TERRITORY: Schedule AG-4 applies everywhere PG&E provides electricity service.

3. RATES: Total bundled service charges are calculated using the total rates shown below. DirectAccess (DA) and Community Choice Aggregation (CCA) charges shall be calculated inaccordance with the paragraph in this rate schedule titled Billing.

TOTAL RATES

Total Customer/Meter Charge Rates Rate A,D Rate B,E Rate C,FCustomer Charge ($ per meter per day) $0.56838 $0.75565 $2.12895TOU Meter Charge ($ per meter per day) $0.22341 $0.19713 $0.19713

(for rate A, B & C)TOU Meter Charge ($ per meter per day) $0.06571 $0.03943 $0.03943

(for rate D, E & F)

Total Demand Rates ($ per kW)Connected Load Summer $7.22 (I) Connected Load Winter $1.06 (I) Maximum Demand Summer $8.74 (I) $4.38 (I)Maximum Demand Winter $1.93 (I) $2.11 (I)Maximum Peak Demand Summer $4.84 (I) $11.50 (I)Maximum Part-Peak Demand Summer $2.18 (I)Maximum Part-Peak Demand Winter $0.48 (I)Primary Voltage Discount Summer (B, E per Maximum

Demand; C, F per Maximum Peak Demand) $0.98 (I) $1.32 (I)

Primary Voltage Discount Winter (B, E, C, F perMaximum Demand)

$0.30 (I) $0.27 (I)

Transmission Voltage DiscountMaximum Peak Demand Summer $5.84 (I)Maximum Part-Peak Demand Summer $1.14 (I)Maximum Demand Summer $0.21 (I)Maximum Part-Peak Demand Winter $0.48 (I)Maximum Demand Winter $1.47 (I)

Total Energy Rates ($ per kWh)Peak Summer $0.39927 (I) $0.26055 (I) $0.24419 (I)Part-Peak Summer $0.14071 (I)Off-Peak Summer $0.17169 (I) $0.13900 (I) $0.10437 (R)Part-Peak Winter $0.17823 (I) $0.13894 (I) $0.11611 (R)Off-Peak Winter $0.14408 (I) $0.11630 (R) $0.10000 (R)


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3. RATES:(Contd.)

TOTAL RATES (Contd.)

PDP Rates (Rate A and C Options Only)

RATE A RATE C

PDP Charges ($ per kWh)All Usage During PDP Event $1.00 ( ) $1.00 ( )

PDP CreditsDemand ($ per kW)Peak Summer - ($2.38)(R)Part-Peak Summer - ($0.41)(R)

Connected Load ($0.98) (R) -

Energy ($ per kWh)Peak Summer ($0.02505)(R)) $0.00000 ( )


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(Continued)


3. RATES:(Contd.):

Total bundled service charges shown on customers bills are unbundled according to thecomponent rates shown below. PDP charges and credits are all generation and are notincluded below

UNBUNDLING OF TOTAL RATES

Customer/Meter Charge Rates: Customer/Meter charge rates provided in the Total Rate section above areassigned entirely to the unbundled distribution component.

Demand Rates by Component ($ per kW) Rate A,D Rate B,E Rate C,FGeneration:

Connected Load Summer $1.47 (I) Connected Load Winter $0.00 ( ) Maximum Demand Summer $2.54 (I) $0.00 ( )Maximum Demand Winter $0.00 ( ) $0.00 ( )Maximum Peak Demand Summer $2.63 (I) $6.07 (I)Maximum Part-Peak Demand Summer $1.04 (I)Maximum Part-Peak Demand Winter $0.00 ( )Primary Voltage Discount Summer (B, E per

Maximum Demand; C, F per Maximum PeakDemand)

$0.61 (I) $1.04 (I)


$0.00 ( ) $0.00 ( )

Transmission Voltage DiscountMaximum Peak Demand Summer $1.97 ((I))Maximum Part-Peak Demand Summer $0.00 ()Maximum Demand Summer $0.00 ()Maximum Part-Peak Demand Winter $0.00 ()Maximum Demand Winter $0.00 ()

Distribution**:

Connected Load Summer $5.75 (I) Connected Load Winter $1.06 (I) Maximum Demand Summer $6.20 (I) $4.38 (I)Maximum Demand Winter $1.93 (I) $2.11 (I)Maximum Peak Demand Summer $2.21 (I) $5.43 (I)Maximum Part-Peak Demand Summer $1.14 (I)Maximum Part-Peak Demand Winter $0.48 (I)Primary Voltage Discount Summer (B, E per

Maximum Demand; C, F per Maximum PeakDemand)

$0.37 (I) $0.28 (I)


$0.30 (I) $0.27 (I)

Transmission Voltage DiscountMaximum Peak Demand Summer $3.87 (I)Maximum Part-Peak Demand Summer $1.14 (I)

Maximum Demand Summer $0.21 (I)Maximum Part-Peak Demand Winter $0.48 (I)Maximum Demand Winter $1.47 (I)

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** Distribution and New System Generation Charges are combined for presentation on customer bills.


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3. RATES:(Contd.):

UNBUNDLING OF TOTAL RATES (Contd.)

Energy Rates by Component ($ per kWh) Generation:Peak Summer $0.16747 (I) $0.12621 (I) $0.14516 (I)Part-Peak Summer $0.08218 (I)Off-Peak Summer $0.07230 (I) $0.07325 (I) $0.05929 (I)Part-Peak Winter $0.07662 (I) $0.07143 (I) $0.06579 (I)Off-Peak Winter $0.06528 (I) $0.06078 (I) $0.05596 (I)

Distribution**:Peak Summer $0.19860 (I) $0.10286 (I) $0.06746 (I)Part-Peak Summer $0.02696 (I)Off-Peak Summer $0.06619 (I) $0.03427 (I) $0.01351 (I)Part-Peak Winter

$0.06841 (I) $0.03603 (I) $0.01875 (I)Off-Peak Winter $0.04560 (I) $0.02404 (I) $0.01247 (I)

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3. RATES:(Contd.)

UNBUNDLING OF TOTAL RATES (Contd.)Energy Rates by Component ($ per kWh) Rate A,D Rate B,E Rate C,FTransmission* (all usage) $0.00982 $0.00982 $0.00982Transmission Rate Adjustments* (all usage) $0.00403 (R) $0.00403 (R) $0.00403 (R)Reliability Services* (all usage) $0.00010 (R) $0.00010 (R) $0.00010 (R)Public Purpose Programs (all usage) $0.01542 (I) $0.01370 (R) $0.01379 (R)Nuclear Decommissioning (all usage) $0.00097 (I) $0.00097 (I) $0.00097 (I)Competition Transition Charges (all usage) $0.00058 (R) $0.00058 (R) $0.00058 (R)Energy Cost Recovery Amount (all usage) ($0.00504)(R) ($0.00504)(R) ($0.00504)(R)DWR Bond (all usage) $0.00526 (I) $0.00526 (I) $0.00526 (I)

New System Generation Charge (all usage)** $0.00206 (R) $0.00206 (R) $0.00206 (R)California Climate Credit (all usage)*** ($0.00302) (I) ($0.00354) (I) ($0.00353) (I)

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* Transmission, Transmission Rate Adjustments,and Reliability Service charges are combined forpresentation on customer bills.


*** Only customers that qualify as Small Businesses California Climate Credit under Rule 1 are eligible forthe California Climate Credit.


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Advice Letter No: 3896-E-B Issued by Date Filed December 30, 20

Decision No. Brian K. Cherry Effective January 1, 20

Vice President Resolution No. E-44


4. METERINGREQUIREMENTS:

PG&E will install a time-of-use meter that is appropriate for this schedule thatmeasures and registers the amount of electricity a customer uses.

Customers with a maximum billing demand of 200 kW or greater for threeconsecutive months must have an interval data meter that can be read remotely byPG&E except customers that are identified as load research sites. A Meter DataManagement Agent (MDMA) may also read the customers meter on behalf of thecustomers Energy Service Provider (ESP) if a customer is receiving Direct AccessService.

For bundled service customers with a maximum demand of 200 kW or greater forthree consecutive months, PG&E will provide and install the interval data meter atno cost to the customer. After the interval meter is installed, the customer musttake service on a time-of-use rate schedule. The installation of an interval datameter for customers taking service under the provisions of Direct Access is the

responsibility of the customers Energy Service Provider, or their Agent, and mustbe installed in accordance with Electric Rule 22.

If the customer does not currently qualify for an interval data meter, the customermust pay PG&E for the cost of purchasing and installing an interval meter, togetherwith applicable Income Tax Component of Contribution (ITCC) charges and the costto operate and maintain the interval meter, and must sign an Interval MeterInstallation Service Agreement (Form 79-984).

Customers who also request any meter data management services must also signan Interval Meter Data Management Service Agreement (Form 79-985) and musthave an appropriate interval data meter.

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5. TIME PERIODS Seasons of the year and times of the day are defined as follows:

SUMMER: Service from May 1 through October 31.

For Rates A, B, D, and E

Peak: 12:00 noon to 6:00 p.m. Monday through Friday*

Off-Peak: All other hours Monday through Friday

All day Saturday, Sunday, holidays

For Rates C and F

Peak: 12:00 noon to 6:00 p.m. Monday through Friday*

Partial-Peak: 8:30 a.m. to 12:00 p.m. Monday through Friday*6:00 p.m. to 9:30 p.m. Monday through Friday*

Off-Peak: 9:30 p.m. to 8:30 a.m. Monday through FridayAll day Saturday, Sunday, holidays

WINTER: Service from November 1 through April 30.

For Rates A, B, C, D, E, and F

Partial-Peak: 8:30 a.m. to 9:30 p.m. Monday through Friday*

Off-Peak: All other hours Monday through Friday

All day Saturday, Sunday, holidays

Holidays for the purpose of this rate schedule are New Year's Day, President's Day, Memorial

Day, Independence Day, Labor Day, Veterans Day, Thanksgiving Day, and Christmas Day.The dates will be those on which the holidays are legally observed.

*Except holidays.

DAYLIGHT SAVING TIME ADJUSTMENT: The time periods shown above will begin and end

one hour later for the period between the second Sunday in March and the first Sunday in April,and for the period between the last Sunday in October and the first Sunday in November.

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6. ENERGY

CHARGE

CALCULATION:

When summer and winter proration is required, charges will be based on the average daily use

for the full billing period times the number of days in each period.

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7. SERVICECONTRACT:

Service under Schedule AG-4 is provided for a minimum of 12 months beginning withthe date service commences. The customer may be required to sign a servicecontract with a minimum term of one year. After the initial one-year term has expired,the contract will continue in effect until it is cancelled by the customer or PG&E.

Where a line extension is required, it will be installed under the provisions of Rules 15and 16.

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8. CONNECTEDLOAD(Rates A and Donly):

Connected load is defined as the sum of the rated capacities (as determined inaccordance with Rule 2) of all equipment that is served through one metering point andthat may be operated at the same time. When charges are based on connected load,in no case will charges be based on less than two horsepower/kilowatts for single-phase service, nor less than three horsepower/kilowatts for three-phase service.

The customers account will be adjusted for permanent connected-load changes that

take place during the contract year. It is the customers responsibility to notify PG&Eof such changes. No adjustment will be made for a temporary reduction in connectedload. If the load is reconnected within 12 months of being disconnected, the chargeswill be recalculated and applied retroactively as though no reduction in load had takenplace.

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9. MAXIMUMDEMAND(Rates B, C, E,and F Only):

The maximum demand will be the number of kW the customer is using recorded over15-minute intervals; the highest 15-minute average in any month for Rates B, C, Eand F customers will be the maximum demand for that month. Where the customersuse of electricity is intermittent or subject to abnormal fluctuation, a 5-minute intervalmay be used. If the customer has any welding machines, the diversified resistancewelder load, calculated in accordance with Section J of Rule 2, will be considered themaximum demand if it exceeds the maximum demand that results from averaging thedemand over 15-minute intervals. The welder load calculation will apply only in theseason in which the customer usually uses energy, which will be assumed to be thesummer season unless otherwise designated.

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9. MAXIMUMDEMAND(Rates B, C, E,and F Only):(Contd.)

In billing periods with use in both the summer season and winter season (April/May,October/November), the customers total demand charge shall be calculated on apro rata basis depending upon the demand charge and the number of days in eachseason. The maximum demand used in determining the customers demand chargefor each season of the billing period will be: (1) the maximum demand created in eachseasons portion of the billing month as measured by a meter with such capability; or(2) the maximum demand for the billing month where the installed meter is incapableof measuring time-varying demands.

For customers for whom Schedule SStandby Service Special Conditions 1 through 6apply, standby demand is the portion of a customer's maximum demand in any monthcaused by nonoperation of the customer's alternate source of power, and for which ademand charge is paid under the regular service schedule.

If the customer imposes standby demand in any month, then the regular service

maximum demand charge will be reduced by the applicable reservation capacitycharge (see Schedule S Special Condition 1).

To qualify for the above reduction in the maximum demand charge, the customer must,within 30 days of the regular meter-read date, demonstrate to the satisfaction of PG&Ethe amount of standby demand in any month. This may be done by submitting toPG&E a completed Electric Standby Service Log Sheet (Form 79-726).

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10. MAXIMUM-PEAK-PERIODDEMAND(Rates B, C, Eand F Only):

The customers maximum-peak-period demand will be the highest of all the 15-minuteaverages for the peak period during the billing month.

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11. MAXIMUM-PART-PEAK-PERIODDEMAND(Rates C and FOnly):

The customers maximum-part-peak-period demand will be the highest of all the15-minute averages for the part-peak period during the billing month.

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12. DEFINITIONOF SERVICEVOLTAGE:

The following defines the three voltage classes of Schedule AG-4 rates. StandardService Voltages are listed in Rule 2, Section B.1.

a. Secondary: This is the voltage class if the service voltage is less than 2,400 voltsor if the definitions of "primary" and "transmission" do not apply to the service.

b. Primary: This is the voltage class if the customer is served from a "single customersubstation" or without transformation from PG&E's serving distribution system atone of the standard primary voltages specified in PG&E's Electric Rule 2, SectionB.1.

PG&E retains the right to change its line voltage at any time. Customers receivingvoltage discounts will get reasonable notice of any impending change. They will thenhave the option not taking service at the new voltage (and making whatever changes intheir system are necessary) or taking service without a voltage discount through

transformers supplied by PG&E.

13. BILLING: A customers bill is calculated based on the option applicable to the customer.

Bundled Service Customersreceive supply and delivery services solely from PG&E.The customers bill is based on the Total Rates and Conditions set forth in this schedule.

Transitional Bundled Service Customerstake transitional bundled service asprescribed in Rules 22.1 and 23.1, or take bundled service prior to the end of the six(6) month advance notice period required to elect bundled portfolio service as prescribedin Rules 22.1 and 23.1. These customers shall pay charges for transmission,transmission rate adjustments, reliability services, distribution, nuclear decommissioning,public purpose programs, New System Generation Charges

1, the applicable Cost

Responsibility Surcharge (CRS) pursuant to Schedule DA CRS or Schedule CCA CRS,and short-term commodity prices as set forth in Schedule TBCC.

Direct Access (DA) and Community Choice Aggregation (CCA) Customerspurchase energy from their non-utility provider and continue receiving delivery servicesfrom PG&E. Bills are equal to the sum of charges for transmission, transmission rateadjustments, reliability services, distribution, public purpose programs, nucleardecommissioning, New System Generation Charges

1, the franchise fee surcharge, and

the applicable CRS. The CRS is equal to the sum of the individual charges set forthbelow. Exemptions to the CRS are set forth in Schedules DA CRS and CCA CRS.

DA / CCA CRS Energy Cost Recovery Amount Charge (per kWh) ($0.00504) (R)

DWR Bond Charge (per kWh) $0.00526 (I)CTC Charge (per kWh) $0.00058 (R)Power Charge Indifference Adjustment (per kWh)

Pre-2009 Vintage ($0.00054) (I)2009 Vintage $0.00971 (I)2010 Vintage $0.01034 (I)2011 Vintage $0.01061 (I)2012 Vintage $0.01051 (I)2013 Vintage $0.01014 (I)2014 Vintage $0.01004 (I)2015 Vintage $0.01004 (N) (N)

_________________1Per Decision 11-12-031, New System Generation Charges are effective 1/1/2012.


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14. STANDBYAPPLICA-BILITY:

SOLAR GENERATION FACILITIES EXEMPTION: Customers who utilize solargenerating facilities which are less than or equal to one megawatt to serve load and whodo not sell power or make more than incidental export of power into PG&Es power gridand who have not elected service under Schedule NEM, will be exempt from paying theotherwise applicable standby reservation charges.

DISTRIBUTED ENERGY RESOURCES EXEMPTION: Any customer under atime-of-use rate schedule using electric generation technology that meets the criteria asdefined in Electric Rule 1 for Distributed Energy Resources is exempt from the otherwiseapplicable standby reservation charges. Customers qualifying for this exemption shallbe subject to the following requirements. Customers qualifying for an exemption fromstandby charges under Public Utilities (PU) Code Sections 353.1 and 353.3, asdescribed above, must take time-of-use service to receive this exemption until a real-

time pricing program, as described in PU Code 353.3, is made available. Onceavailable, customers qualifying for the standby charge exemption must participate in thereal-time program referred to above. Qualification for and receipt of this distributedenergy resources exemption does not exempt the customer from metering chargesapplicable to time-of-use (TOU) and real-time pricing, or exempt the customer fromreasonable interconnection charges, non-bypassable charges as required in PreliminaryStatement BB - Competition Transition Charge Responsibility for All Customers andCTC Procurement, or obligations determined by the Commission to result fromparticipation in the purchase of power through the California Department of WaterResources, as provided in PU Code Section 353.7.

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15. DWR BONDCHARGE:

The Department of Water Resources (DWR) Bond Charge was imposed by CaliforniaPublic Utilities Commission Decision 02-10-063, as modified by Decision 02-12-082, andis property of DWR for all purposes under California law. The Bond Charge applies to allretail sales, excluding CARE and Medical Baseline sales. The DWR Bond Charge(where applicable) is included in customers total billed amounts.

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Advice Letter No: 3993-E Issued by Date Filed January 26, 20

Decision No. Brian K. Cherry Effective March 30, 20



16. PEAK DAYPRICINGDETAILS:

a. Default Provision: The default of eligible customers to PDP will occur once per yearwith the start of their billing cycle on or after March 1. Eligible customers will haveat least 45-days notice prior to their planned default date when they may opt-out ofPDP rates to take service on TOU rates. During the 45-day period, customers willcontinue to take service on their non-PDP rate. Customers may elect anyapplicable PDP rate. However, if the customers taking service on this schedulehave not made that choice or elected to opt-out to a TOU at least five (5) daysbefore their proposed default date, their service will be defaulted to the PDP versionof this rate schedule. Existing customers on a PDP rate eligible demand responseprogram will have the option to enroll.

b. Bill Stabilization: PDP customers will be offered bill stabilization for the initial twelve(12) months unless they opt-out during their initial 45-day period. Bill stabilizationensures that during the initial 12 months under PDP, the customer will not pay morethan it would have had it opted-out to the applicable TOU rate.

If a customer terminates its participation on the PDP rate prior to the initial 12 monthperiod expiring, the customer will receive bill stabilization up to the date when thecustomer terminates its participation. Bill stabilization benefits will be computed ona cumulative basis, based on the earlier of 1) when a customer terminates itsparticipation on the PDP rate or 2) at the end of the initial 12-month period. Anyapplicable credits will be applied to the customers account on a subsequent regularbill. Bill stabilization is only available one time per customer. If a customer un-enrolls or terminates their participation on a PDP rate, bill stabilization will not beoffered again.

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Cancelling Original Cal. P.U.C. Sheet No. 29118Pacific Gas and Electric CompanySan Francisco, CaliforniaU 39



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16. PEAK DAYPRICINGDETAILS(CONTD):

c. Notification Equipment: At the customers option and expense, it is recommended,but not required that a customer provide a phone number or an e-mail address toreceive automated notification messages of a PDP event from PG&E.

If a PDP event occurs, customers will be notified using one or more of the above-mentioned systems. Receipt of such notice is the responsibility of the participatingcustomer. PG&E will make reasonable efforts to notify customers, however it is thecustomers responsibility to receive such notice and to check the PG&E website tosee if a PDP event has been activated. It is also the customers responsibility tomaintain accurate notification contact information. PG&E does not guarantee thereliability of the phone, e-mail system, or Internet site by which the customerreceives notification.

PG&E may conduct notification test events once a month to ensure a customerscontact information is up-to-date. These are not actual PDP events and no loadreduction is required.

d. Demand Response Operations Website: Customers with demands of 200 kW orgreater for three consecutive months can use PG&Es demand response operationswebsite located at https://inter-act.pge.com for load curtailment event notificationsand communications.

The customers actual energy usage is available at PG&Es demand responseoperations website or on My Account. This data may not match billing qualitydata, and the customer understands and agrees that the data posted to PG&Esdemand response operations website or My Account may be different from theactual bill.

e. Program Operations: A maximum of fifteen (15) PDP events and a minimum ofnine (9) PDP events may be called in any calendar year. PG&E will notify customersby 2:00 p.m. on a day-ahead basis when a PDP event will occur the next day. ThePDP program will operate year-round and PDP events may be called for any day ofthe week.

f. Event Cancellation: PG&E may initiate the cancellation of a PDP event before 4:00p.m. the day-ahead of a noticed PDP event. If PG&E cancels an event, it will countthe cancelled event toward the PDP limits.

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Cancelling Original Cal. P.U.C. Sheet No. 29119Pacific Gas and Electric CompanySan Francisco, CaliforniaU 39






16. PEAK DAYPRICINGDETAILS(CONTD):

g. Program Options: Customers may customize their PDP participation. The followingoptions are available:

1) Days of Consecutive Operation: Customers may choose either a) no limit on thenumber of consecutive PDP events or b) every other PDP event. Customerselecting every other PDP event will be divided into two groups and only besubject to a maximum of one-half of the PDP events called and thecorresponding PDP rate credits will be reduced by 50%. Customers that do notelect an option will be defaulted to the no limit on the number of consecutivePDP events.

2) Duration of PDP Event Operations: Customers may choose either a) 2:00 to6:00 p.m. (four-hour window) or b) 12:00 p.m. to 6:00 p.m. (six-hour window).

Customers electing the longer event operation window between 12:00 p.m. to6:00 p.m. will only be subjected to a reduced level of PDP charges (two-thirds ofthe PDP charge listed in the rates section). Customers that do not elect anoption will be defaulted to the 2:00 p.m. to 6:00 p.m. operation.

h. Event Trigger: PG&E will trigger a PDP event when the day-ahead temperatureforecast trigger is reached. The trigger will be the average of the day-aheadmaximum temperature forecasts for San Jose, Concord, Red Bluff, Sacramento andFresno.

Beginning May 1 of each summer season, the PDP events on non-holidayweekdays will be triggered at 98 degrees Fahrenheit (F), and will be triggered at105F on holidays and weekends. If needed, PG&E will adjust the non-holidayweekday trigger up or down over the course of the summer to achieve the range of9 to 15 PDP events in any calendar year. Such adjustments would be made nomore than once per month and would be posted to the demand responseoperations website or on PG&Es PDP website.

PDP events may also be initiated as warranted on a day-ahead basis by 1) extremesystem conditions such as special alerts issued by the California IndependentSystem Operator, 2) under conditions of high forecasted California spot marketpower prices, 3) to meet annual PDP event limits for a calendar year, or 4) fortesting/evaluation purposes.

i. Program Terms: A customer may opt-out anytime during their initial 12 months ona PDP rate. After the initial 12 months, customers participation will be inaccordance with Electric Rule 12.

Customers may opt-out of a PDP rate at anytime to enroll in another demandresponse program beginning May 1, 2011.

j. Interaction with Other PG&E Demand Response Programs: Customers on a PDPrate may participate in a day-of dispatchable demand response program asestablished in D.09-08-027.

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Documents

Electric Schedule AG-4 - Jan 2015