GUIDE TO THE IMPLEMENTATION OF -...

GUIDE TO THE IMPLEMENTATION OF TENANT SUBMETERING AND BILLING FOR

COMMERCIAL BUILDINGS IN NORTHERN CALIFORNIA

The Building Owners and Managers Association of California May 2008

GUIDE TO THE IMPLEMENTATION OF

TENANT SUBMETERING AND BILLING FOR COMMERCIAL BUILDINGS IN

NORTHERN CALIFORNIA

Introduction

Consistent with its efforts to improve the efficiency of California’s electrical system, the California Public Utilities Commission (CPUC) has approved a Settlement Agreement between the Building Owners and Managers Associations of San Francisco and of California (BOMA) and Pacific Gas and Electric Company (PG&E) that creates new options for the allocation of commercial building electricity costs and provides tenants with price signals and incentives for managing their electricity consumption and reducing costs. The new decision (D.07-09-004) also offers the potential for eliminating the inequities among tenants that are inherent in square footage-based electricity cost allocation schemes. This decision changes PG&E’s Rules 1 and 18 to allow the option of the installation of tenant submeters in high rise buildings and the billing of tenants according to their measured electricity usage. This Guide describes the rules for building owners to follow in the implementation of tenant submetering and billing, as dictated by the CPUC. A copy of the full text of Decision 07-09-004 is provided in Attachment F. Copies of PG&E’s Rules 1 and 18 are provided in Attachment A.

Guidelines for Building Owners

The basic motivation of the decision is to allow commercial building tenants to receive dynamic price signals and information about their individual energy usage and cost, and to give tenants the opportunity to participate in energy conservation and load management programs for managing and reducing their energy costs. The decision sets forth rules governing the buildings that qualify for submetering, information that building owners must provide to tenants, the capabilities of meters that are installed, and the cost allocations that are permitted. Following is a summary of those rules:

Authorization to submeter and bill tenants according to measured usage applies only under the following conditions in accordance with PG&E Rule 18:

o Where service is supplied to a high rise building which is owned or

managed by a single entity on a single premises (PG&E’s Rule 1 – High Rise Building: A multi-story, multi-tenant building located on single premises usually comprised of three or more stories and equipped with elevators) ; and

2

o Where a master-meter customer (building owner) installs, owns, and maintains electric submeters on its existing building’s distribution system for cost allocation of dynamic pricing and/or conservation incentive purposes the cost of electricity allocated to the commercial building tenants will be billed at the same rate as the master meter billed by PG&E under the CPUC approved rate schedule servicing the master meter.

Tenant submetering and billing will be optional, subject to mutual agreement between owners and tenants and specified in leases.

All attachments and devices on the customer's side of the master meter used to measure tenant electricity use for the purposes of billing and taking advantage of dynamic pricing and energy conservation opportunities shall conform to all applicable safety rules, regulations, and general orders established by state (specifically, Chapter 4 of the California Code of Regulations) and local governments. Specifically, submeters must be installed and tested in accordance with the Code of Regulations and have the capability to provide the same revenue quality billing measurements as the master meter serving the building.

Building owners installing submeters should provide all tenants with the following information:

o The PG&E rate schedule serving the master meter (Attachment B).

o The contact information for PG&E (Attachment C).

o The contact information for the California Department of Food and Agriculture, Division of Measurement Standards meter complaint process (Attachment D).

o Notification that tenant controlled energy charges will be removed from rent when submetering commences.

o Information concerning dynamic pricing options and all energy conservation and load management programs available for submetered tenant participation.

Building owners installing submeters will be allowed to recover the costs of metering, billing, and information services, according to terms jointly agreed to by tenants and owners and specified in leases. The costs for such services will be optional for tenants and vary by the effort required to provide the services, and the features of the services elected by the tenant (e.g. real time tracking and monitoring of usage, warning systems, etc.).

Tenant electricity bills should resemble PG&E bills and include the

following information:

3

4

o Tenant metered energy (KWh) and demand (KW) and associated

charges by TOU period in the same level of detail as shown on PG&E’s bill to the building owner.

o Tenant allocations of customer charges plus energy and demand

charges for common area usage, and other consumption exclusive of tenant measured usage. Such tenant allocations should be in accordance with allocation methods specified in leases (such as square footage of occupied space) and can not be based on tenant measured usage.

o Charges for submetering, billing and information services. o Sufficient information to permit tenants to replicate bill calculations

Tenant disputes regarding meter and billing accuracy should first be brought to the attention of the building owner. If a tenant is not satisfied with the response, and the issue is regarding meter accuracy, the tenant can contact the County Sealer of Weights and Measures and arrange for a meter test. If the issue has to do with billing accuracy, the tenant can contact PG&E, and PG&E will explain to the tenant how it bills the master-meter.

Building owners installing submeters are urged to support the PG&&E/BOMA reporting requirements specified in Attachment E to provide the California Public Utilities Commission with information necessary for evaluating the effects of changing Rule 18 to allow submetering.

For PG&E’s next Phase 2 GRC, PG&E and BOMA should conduct a statistically significant survey regarding commercial building master metering experience to date, in order to answer the questions listed in Attachment E.

Attachments:

A – PG&E Rule 1 and Rule 18 B – PG&E Rate Schedules E-19 and E 20 C – PG&E Contacts D – California Division of Measurement Standards Contacts E – PG&E/BOMA Survey Questions F – CPUC Decision 07-09-004

Attachment A – PG&E Rule 1 and Rule 18

Revised Cal. P.U.C. Sheet No. 25914-E Cancelling Revised Cal. P.U.C. Sheet No. 14855-E

Pacific Gas and Electric Company San Francisco, California U 39

ELECTRIC RULE NO. 1 Sheet 1

DEFINITIONS

(Continued)

Advice Letter No: 2948-E-A Issued by Date Filed January 18, 2007Decision No. 06-11-030 Brian K. Cherry Effective November 30, 2006 Vice President Resolution No. 1C1 Regulatory Relations

ACCOUNT: A PG&E-specific identifier for tracking energy service deliveries for a specific load through one or more meters at a customer premises or location. One customer may have several accounts within a premises or throughout PG&E�’s service territory.

AGRICULTURAL CUSTOMER: Please see �“QUALIFICATION FOR AGRICULTURAL RATES.�”

(N) (N)

APPLICANT: A person or agency requesting PG&E to supply electric service or for changes in electric service. Electric service may consist of both energy and energy-related services.

APPLICATION: An oral, electronic, or a written request to PG&E for electric service; not an inquiry as to the availability or charges for such service. The form of the request shall be at PG&E�’s discretion.

Revised Cal. P.U.C. Sheet No. 16368-E Cancelling Original Cal. P.U.C. Sheet No. 14856-E



DEFINITIONS

(Continued)

Advice Letter No: 1867-E Issued by Date Filed April 28, 1999Decision No. Thomas E. Bottorff Effective July 1, 1999 Vice President Resolution No. 2C1 Rates Account Services

BASELINE: A rate structure mandated by the California Legislative and implemented at PG&E in 1984 that insures all residential customers are provided a minimum necessary quantity of electricity at the lowest possible cost.

BILLING CYCLE: The regular interval at which a bill for electric service is rendered; typically spans a 27-to-33 day period.

BILLING DEMAND: The demand on which the customer is to be billed in accordance with the terms and conditions of their applicable rate schedule.

BILLING FACTOR: Factor used to calculate a bill on a daily basis as opposed to monthly, when the billing period is other than 27 to 33 days. All rate schedules assume monthly billings of 27 to 33 days, and the Billing Factor for these billings is equal to 1. The factor is used to adjust flat monthly charges (such as fixed usage accounts), monthly customer, monthly meter, and minimum service charges to monthly parity when an account is billed for fewer than 27 days (Billing Factor is less than 1), or when billed for more than 33 days (Billing Factor is greater than 1). The factor is based on 30 days, which are deemed to be the total number of days in an average month. The Billing Factor formula is:

Billing Factor = Number of Billing Days divided by 30.

(T) (T)

(C) BILLING MONTH: The period of time over which a customer is billed for services rendered during a particular billing cycle.

BUNDLED SERVICE: Defined in Rule 22.A.1.

BUSINESS DAY: A day on which PG&E offices are open to conduct general business in California. Also, commonly referred to as a �“working�” day.




DEFINITIONS

(Continued)

Advice Letter No: 1716-E Issued by Date Filed December 1, 1997Decision No. 97-10-087 Thomas E. Bottorff Effective January 10, 1998 Vice President Resolution No. 3C1 Rates Account Services

CALIFORNIA ALTERNATE RATES FOR ENERGY (CARE): The residential CARE (formerly known as Low-Income Ratepayer Assistance or LIRA) program for qualifying (see Rules 19.1 and 19.2) low-income applicants provides reduced energy charges to the following:

1. Individually metered customers;

2. Master-metered customers with qualifying low-income submetered tenants;

3. Submetered tenants of master-metered PG&E customers;

4. Qualifying residents in individually metered residential dwelling units; and

5. Qualifying Nonprofit Group-Living Facilities.

(T)(T)

(L) | | | | | | | | | | | |

(L)

CARE NONPROFIT GROUP-LIVING FACILITY: A facility operated by a corporation that has received a letter of determination by the Internal Revenue Service that the corporation is tax-exempt due to its nonprofit status under IRS Code Section 501(c)(3). The facility must be one of the following:

1. A homeless shelter with 10 or more beds and open at least 180 days per year;

2. Transitional housing, such as a half-way house or drug rehabilitation facility;

3. Short- or long-term care facility, such as a hospice, nursing home, seniors' home, or children's home; or

4. A group home for physically or mentally disabled persons.

With the exception of homeless shelters, the nonprofit group-living facility must provide services such as meals or rehabilitation in addition to lodging. All of the residents of the facility must meet the CARE eligibility standard for a single-person household. At least 70 percent of the electricity supplied to the facility's premises must be used for residential purposes, and the facility must be licensed by the appropriate state agency, with the exception of homeless shelters which must have the appropriate municipal or county conditional use permits.

Facilities such as student housing/dormitories are excluded.

For complete eligibility requirements see Rule 19.2.

(T)

(T)

Revised Cal. P.U.C. Sheet No. 25524-E* Cancelling Revised Cal. P.U.C. Sheet No. 23005-E



DEFINITIONS

(Continued)

Advice Letter No: 2784-E-A Issued by Date Filed November 29, 2006Decision No. 05-12-041 Brian K. Cherry Effective November 9, 2006 Vice President Resolution No. E-40134C1 Regulatory Relations

COMMISSION: The Public Utilities Commission of the State of California, sometimes referred to as the Public Utilities Commission (PUC) or the CPUC.

COMMON USE AREAS: Those areas that may be shared or used by occupants within a multifamily accommodation, including, but not limited to, laundry room, recreation room, swimming pool, tennis courts, gardens, hall/outdoor lighting.

COMPANY: Pacific Gas and Electric Company (PG&E).

COMMUNITY CHOICE AGGREGATION SERVICE (CCA SERVICE): This service allows customers to purchase electric power, and at the customer�’s election, participate in additional energy efficiency or conservation programs from non-utility entities known as Community Choice Aggregators. Herein all references to Community Choice Aggregation mean the same as CCA Service.

(T) (T)

COMMUNITY CHOICE AGGREGATOR (CCA): An entity that provides electric supply services to Community Choice Aggregation customers within PG&E�’s service territory. A CCA may also provide certain energy efficiency and conservation programs to its Community Choice Aggregation customers as provided for under PG&E�’s tariffs.

(T)

(T)




DEFINITIONS

(Continued)

Advice Letter No: 3153-E-A Issued by Date Filed February 20, 2008Decision No. 07-07-019 Brian K. Cherry Effective May 12, 2008 Vice President Resolution No. 5C2 Regulatory Relations

COMPANY�’S OPERATING CONVENIENCE: The use, under certain circumstances, of facilities or practices not ordinarily employed which contribute to the overall efficiency of PG&E�’s operations; the term does not refer to customer convenience nor to the use of facilities or adoption of practices required to comply with applicable laws, ordinances, rules, regulations, or similar requirements of public authorities.

COMPETITIVE TRANSITION CHARGE (CTC): Defined in Public Utilities Code Section 840 and by the Commission.

CONNECTED LOAD: The sum of the rated capacities of all of the customer�’s equipment that can be connected to PG&E�’s lines at any one time as more completely described in the rate schedules.

COST OF OWNERSHIP: A monthly charge applied to special facilities to recover the cost to PG&E of operating the special facility.

When applicant-financed the charge includes the cost components for operations and maintenance (O&M), administration and general expenses (A&G), property taxes, and franchise fees and uncollectibles, and the cost of replacement facilities facilities at no additional cost for sixty (60) years The applicant-financed percentage is also used to calculate COO charges on unsupported distribution line extension costs. See Rule 15.E.6

When PG&E-financed the monthly cost components include all of those listed above for applicant-financed special facilities plus components to cover the costs of income taxes, return on investment, and depreciation. . The PG&E-financed COO is also used to calculate line extension allowances. (See Rule 15. C. 2 & C.3.

(N) | | | | | | | | | | | | |

(N)




DEFINITIONS

(Continued)

Advice Letter No: 2628-E Issued by Date Filed February 14, 2005Decision No. 04-12-046 Karen A. Tomcala Effective February 14, 2005 Vice President Resolution No. 6C1 Regulatory Relations

CPUC (CALIFORNIA PUBLIC UTILITIES COMMISSION): The Public Utilities Commission of the State of California.

CURTAILMENT: The temporary reduction or interruption of service to customers because of projected or actual supply or capacity constraints, as further defined in Rule 14 and PG&E's Electrical Emergency Plan. PG&E may also request such load reduction under the provisions of its nonfirm programs.

CUSTOMER: The person, group of persons, firm, corporation, institution, municipality, or other civic body, in whose name service is rendered, as evidenced by the signature on the application, contract, or agreement for that service or, in the absence of a signed instrument, by the receipt and payment of bills regularly issued in that name, regardless of the identity of the actual user of the service. A customer may take Bundled Service or Direct Access Service or Community Choice Aggregation Service, but must take final delivery of electric power, and not resell that power.

(T)

Original Cal. P.U.C. Sheet No. 14861-E Cancelling Revised Cal. P.U.C. Sheet No. 14141-E



DEFINITIONS

(Continued)


CUT-IN-FLAT: Placing conductive material in the electric meter socket to allow energy to flow from the line side of the service to the load side of the service without a meter.

(L) (L)

DEMAND: The amount of energy drawn by a Customer at a specific time. Typically expressed in kilowatts or kW.

(N) | |

DEMAND CHARGE: One component of an electric customer�’s bill (along with, but not limited to, the customer charge, meter charge, and the energy charge). This charge recovers some of the costs PG&E incurs in providing sufficient operating capacity to meet that customer�’s maximum demand. The demand charge is based on the highest level of kW required by the customer during a billing period.

| | | |

(N)




DEFINITIONS

(Continued)

Advice Letter No: 2627-E Issued by Date Filed February 14, 2005Decision No. Karen A. Tomcala Effective January 1, 2005 Vice President Resolution No. 8C1 Regulatory Relations

DIRECT ACCESS SERVICE: Defined in Rule 22.A.3. (T)

DISTRIBUTED ENERGY RESOURCES (DER) means any electric generation technology that meets all of the following criteria:

(a) Commences initial operation between May 1, 2001, and June 1, 2003, except that gas-fired distributed energy resources that are not operated in a combined heat and power application must commence operation no later than September 1, 2002.

(b) Is located within a single facility.

(c) Is five megawatts or smaller in aggregate capacity.

(d) Serves onsite loads or over-the-fence transactions allowed under Sections 216 and 218.

(e) Is powered by any fuel other than diesel.

(f) Complies with emission standards and guidance adopted by the State Air Resources Board pursuant to Sections 41514.9 and 41514.10 of the Health and Safety Code. Prior to the adoption of those standards and guidance, for the purpose of this article, distributed energy resources shall meet emissions levels equivalent to nine parts per million oxides of nitrogen, or the equivalent standard taking into account efficiency as determined by the State Air Resources Board, averaged over a three-hour period, or best available control technology for the applicable air district, whichever is lower, except for distributed generation units that displace and therefore significantly reduce emissions from natural gas flares or reinjection compressors, as determined by the State Air Resources Control Board.

These units shall comply with the applicable best available control technology as determined by the air pollution control district or air quality management district in which they are located. This definition is obtained from Public Utilities Code (PUC) 353.1. The definition of DER may be modified as necessary to be consistent with any changes ordered by the appropriate jurisdiction.

(N) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

(N)

DISTRIBUTION SERVICES: The delivery of electrical supply and related services by PG&E to a customer over PG&E�’s Distribution System.

DISTRIBUTION SYSTEM: Those non-ISO transmission and distribution facilities owned, controlled, and operated by PG&E that are used to provide Distribution Service under these tariffs.

(L)




DEFINITIONS

(Continued)

Advice Letter No: 3115-E-A Issued by Date Filed December 27, 2007Decision No. 07-09-004 Brian K. Cherry Effective January 1, 2008 Vice President Resolution No. E-41219C1 Regulatory Relations

ELECTRONIC BILLING: A billing method whereby at the mutual option of the Customer and PG&E, the Customer elects to receive, view, and pay bills electronically and to no longer receive paper bills.

ELECTRONIC PRESENTMENT: When made available or transmitted electronically to the Customer at an agreed upon location.

ENERGY SUPPLY OR PROCUREMENT SERVICES: Includes, but is not limited to, procurement of electric energy; all scheduling, settlement, and other interactions with Scheduling Coordinators, and the ISO; all ancillary services and congestion management.

ENERGY SERVICE PROVIDER (ESP): An entity who provides electric supply services to Direct Access Customers within PG&E�’s service territory. An ESP may also provide certain metering and billing services to its DA Customers as provided for within these tariffs.

FEDERAL ENERGY REGULATORY COMMISSION (FERC): Federal agency with jurisdictional responsibilities over electric transmission service and electric sales for resale.

FIXED TRANSITION AMOUNT (FTA) CHARGE: See Trust Transfer Amount Charge.

GENERATION CUSTOMER: Any PG&E (electric customer with electric generation facilities (including back-up generation in parallel with PG&E) on the customer's side of the interconnection point.

HIGH RISE BUILDING: A multi-story, multi-tenant building located on single premises usually comprised of three or more stories and equipped with elevators.

(N) (N)

HOURLY PRICING OPTION: This option is suspended.

INDEPENDENT SYSTEM OPERATOR (ISO): The California Independent System Operator Corporation, a state-chartered, non-profit corporation that controls the transmission facilities of all participating transmission owners and dispatches certain generating units and loads. The ISO is responsible for the operation and control of the statewide transmission grid.




DEFINITIONS

(Continued)


INDIVIDUAL METERING: The deployment of a separate service and meter for each individual residence, apartment dwelling unit, mobilehome space, store, office, etc.

(T) (L) (L)

INTERRUPTION: Unscheduled disruption of power deliveries to one or more Customers resulting from transmission or distribution capacity shortages.

(N) (N)

KILOWATT: 1,000 watts; a watt is a unit of electrical power equal to a current of one ampere under one volt of pressure.

(T)(T)

(L) | |

KILOWATT-HOUR: 1,000 watts, or one (1) kilowatt of electricity used for one hour. (T) (L)

LOAD PROFILES: An approximation of a Customer�’s electric usage pattern as approved by the Commission for certain purposes set forth in PG&E�’s tariffs.

(N) (N)

LOW INCOME RATE PAYER ASSISTANCE: See California Alternate Rates for Energy. (T) (L)




DEFINITIONS

(Continued)


MAILED: When a communication is sent by electronic data interchange or enclosed in a sealed envelope, properly addressed, and deposited In any U.S. Post Office box, postage prepaid.

(T) (L)

MANDATED SAFETY AND LEGAL NOTICES: Mandated notices include notices required to be sent to all PG&E customers by law and include, but are not limited to, notices of the type, and with the frequency, that PG&E has used, and continues to use, to discharge legal obligations, such as quarterly Proposition 65 notices, quarterly notices of rate options applicable to each customer class, notices of rate applications, and notices of public assistance and low income programs.

(N)| | | |

(N)

MASTER-METERING: Where PG&E installs one service and meter to supply more than one residence, apartment dwelling unit, mobilehome space, store, office, etc.

METER: The instrument that is used for measuring the electricity delivered to the Customer.

(T) |

(T)

(L)

Original Cal. P.U.C. Sheet No. 19403-E* Cancelling Revised Cal. P.U.C. Sheet No. 14866-E



DEFINITIONS

(Continued)

Advice Letter No: 2281-E-A Issued by Date Filed December 27, 2002Decision No. Karen A. Tomcala Effective February 27, 2003 Vice President Resolution No. 12C1 Regulatory Relations

MOBILEHOME: A structure designed for human habitation and for being moved on a street or highway under permit pursuant to the California Vehicle Code, or a manufactured home as defined in the California Health and Safety Code. A recreational vehicle or a commercial coach as defined in the California Health and Safety Code is not a mobilehome.

MOBILEHOME PARK: An area of land where two or more mobilehome sites are rented, or held out for rent, to accommodate mobilehomes used for human habitation. A recreational vehicle park is not a mobilehome park.

MULTIFAMILY ACCOMMODATION: An apartment building, duplex, court group, residential hotel, or any other group of residential units located upon a single premises, providing the residential units meet the requirements for a residential dwelling unit. Hotels, guest or resort ranches, tourist camps, motels, auto courts, rest homes, rooming houses, boarding houses, dormitories, trailer courts, consisting primarily of guest rooms and/or transient accommodations, are not classed as multifamily accommodations.




DEFINITIONS

(Continued)


OPTIONAL RATE SCHEDULES: Commission-approved rate schedules for a customer class from which any customer in that class may choose. Optional rate schedules do not include experimental schedules or schedules available at the sole option of PG&E.

PAID OR PAYMENT: Funds received by PG&E through the postal service, PG&E payment office, PG&E authorized agent, or deposited in PG&E's bank account by electronic data interchange.

(T)

PERSON: Any individual, partnership, corporation, public agency, or other organization operating as a single entity.




DEFINITIONS

(Continued)

Advice Letter No: 2328-E-B Issued by Date Filed January 23, 2003Decision No. 02-12-045 Karen A. Tomcala Effective January 1, 2003 Vice President Resolution No. 14C1 Regulatory Relations

(D) | | | |

| |

(D) POWER FACTOR: The percent of total power delivery (kVA) which does useful work. For billing purposes, average power factor is calculated from a trigonometric function of the ratio of reactive kilovolt-ampere-hours to the kilowatt-hours consumed during the billing month.

PREMISES: All of the real property and apparatus employed in a single enterprise on an integral parcel of land undivided, excepting in the case of industrial, agricultural, oil field, resort enterprises, and public or quasi-public institutions, by a dedicated street, highway or public thoroughfare or railway. Automobile parking lots constituting a part of and adjacent to a single enterprise may be separated by an alley from the remainder of the Premises served.




DEFINITIONS

(Continued)


PUBLIC PURPOSE PROGRAMS CHARGES: A non-bypassable surcharge imposed on all retail sales of electricity and electrical services to fund public goods research, development and demonstration, energy efficiency activities, and low income assistance programs.

PUBLIC UTILITIES COMMISSION: The Public Utilities Commission of the State of California.

QUALIFICATION FOR AGRICULTURAL RATES:

A. Applicability

1. A customer will be served under an agricultural rate schedule if 70% or more of the annual energy use on 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.

2. Only agricultural end-uses performed prior to the First Sale of the agricultural product are agricultural end-uses under this criteria, except for the following activities, which are also agricultural end-uses under this criteria: (a) packing and packaging of the agricultural products following the First Sale and before any subsequent sale, and (b) agricultural end-uses by nonprofit cooperatives.

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

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

(N) | | | | | | | | | | | | | | | | | | | | | | | | | | | |

(N)

Original Cal. P.U.C. Sheet No. 25916-E Cancelling Cal. P.U.C. Sheet No.



DEFINITIONS

(Continued)


QUALIFICATION FOR AGRICULTURAL RATES: (Cont�’d.)

B. Other Activities and Meters Also Served on Agricultural Rates

The specific language in Section B controls over the language of Sections A, C, and D for only those activities and meters listed in Section B and has no precedential effect on other activities and meters not specifically listed in Section B.

1. Activity-Based Qualification

The following activities will be served on agricultural rates provided that 70% or more of the annual energy usage on the meter is for activities listed in Section B(1) below:

(a) Activities specifically adjudicated by the CPUC in its decisions and orders to be agricultural end-uses prior to March 2, 2006 shall remain on PG&E�’s agricultural rates. These activities are: milk processing, cotton ginning, almond hulling and shelling, and a feed mill integral to the operation of an agricultural end-use.

(b) The following activities determined by PG&E to be agricultural end-uses shall be served on agricultural rates: sun-dried raisin packing, pistachio hulling and shelling, rice drying, hulling and milling necessary to produce white rice, and packing of brown and white rice, but no grinding, crushing, parboiling, cooking, or gelatinizing of rice.

2. Meter-Based Qualification

Any meter (other than meters qualifying in Section B(1) above) on agricultural rates prior to March 2, 2006 shall remain on agricultural rates provided that (1) energy usage on the meter continues to meet the Applicability Statement in effect at that time; and (2) metered usage remains, without interruption, in the name of the present account holder or to anyone who states by declaration that:

(a) they have had a legal or financial interest in the agricultural endeavor for at least two (2) years prior to the change in ownership and have not compensated others or been compensated as a result of the transfer of ownership; or

(b) they have been a bona fide employee, working at least 25 hours per week during the active operating season of the agricultural endeavor, for the last two (2) calendar years prior to the transfer of ownership; or

(N) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

(N)




DEFINITIONS

(Continued)



B. Other Activities and Meters Also Served on Agricultural Rates (Cont�’d.)

2. Meter-Based Qualification (Cont�’d.)

(c) they are the lineal descendants of one of the owners of the agricultural endeavor; or

(d) they are the spouse or former spouse of an owner of the agricultural endeavor.

3. All activities or meters qualifying for an agricultural rate under Sections B(1) or B(2) above shall not serve as precedent or be considered in any other way in determining eligibility under the Agricultural Applicability Statement except as provided in Section B.

C. Specific Applications of the March 2, 2006 Applicability Criteria

Activities identified as agricultural end-uses in this section must also meet the criteria set forth in Section A, with the exception of the processing limitation in Section A(3). Where an actual or perceived conflict exists between Section A and an activity expressly identified as an agricultural end-use in Section C, the specific language of Section C will control over the processing limitation in Section A(3). Any activity not expressly identified as an agricultural end-use in Section C must meet the criteria in Section A in order to be served on agricultural rates.

1. Activities involved in growing crops up to the conclusion of the harvest operation on the premises where the crop was grown are agricultural end-uses.

2. Raising livestock, poultry and fish up to, but not including, the point that the animal is slaughtered or its life terminated in any other operation is an agricultural end-use.

3. Pumping water for irrigation or frost protection of crops, or for reclamation of agricultural land is an agricultural end-use.

(N) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

(N)




DEFINITIONS

(Continued)



C. Specific Applications of the March 2, 2006 Applicability Criteria (Cont�’d.)

4. Drying, hulling, and shelling of grains, legumes, and nuts are agricultural end-uses but not the following:

(a) Other processing or ensiling grain, grain corn, hay, or any other agricultural product;

(b) Activities whose purpose is to change or enhance the flavor of the agricultural product including, but not limited to, roasting, cooking, blanching, salting, curing, and brining;

(c) Oil pressing, processing, and manufacturing to produce oil from corn, safflower, cottonseed, sunflower, and peanut;

(d) Separation or processing of seed from agricultural, vegetable, or flower seed crops, including alfalfa, Bermuda grass, and clover;

5. Waxing, fumigation, irradiation, cleaning, sorting, grading, packing and storage of whole fresh grapes, berries, and other fruits and vegetables are agricultural end-uses, but not the following:

(a) Activities which separate the harvested product into more than one constituent agricultural product, as listed by California Agricultural Statistics Service in their most recent California Statistics Report.

(b) Activities which are part of processes whose purpose is to change or enhance the flavor of the agricultural product, including roasting, cooking, blanching, salting, curing, brining, and any other flavor altering processes.

(c) Pitting or dehydrating of fruits including, but not limited to, plums, grapes, and apricots;

(d) Post-harvest husking or removal of fresh sweet corn kernels from the cob;

(e) Crushing or juicing of fruits and vegetables, including but not limited to grapes, apples, and carrots;

(N) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

(N)




DEFINITIONS

(Continued)



C. Specific Applications of the March 2, 2006 Applicability Criteria (Cont�’d.)

5. (Cont�’d.)

(f) Peeling of garlic and onions and post-harvest processing of multiple baby carrots from individual, harvested, mature carrots;

(g) Olive oil pressing, processing, or manufacturing;

(h) Post-harvest chopping or leafing of lettuce heads or other vegetables and fruits; and

(i) The processing of milk into cheese, yogurt, lactose-free milk, chocolate milk or any other products which do not have the appearance and physical characteristics of fluid milk.

6. Manufacturing of ice used by the manufacturer for the immediate cooling of whole fresh fruits and vegetables is an agricultural end-use, but not manufacturing of ice for sale.

7. Cleaning, packing, grading, sorting, and storage of fresh eggs are agricultural end-uses.

8. Raising crops or live plants in a greenhouse is an agricultural end-use.

9. Raising plants or fish through aquaculture is an agricultural end-use.

10. Cold storage, but not freezing, and other controlled environment storage which merely retards or accelerates the natural ripening of whole unaltered fresh fruits and vegetables is an agricultural end-use.

D. Guidelines for Applying the Applicability Criteria

The following guidelines shall be used to determine whether a customer shall be served under agricultural rates under the Applicability Criteria in Sections A and C.

(N) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

(N)




DEFINITIONS

(Continued)



D. GUIDELINES FOR APPLYING THE APPLICABILITY CRITERIA (Cont�’d.)

1. PRODUCTION FOR SALE

All agricultural products or a subsequent product derived therefrom must be produced for sale to qualify under this criteria. If an activity is primarily for the provision of an agricultural service, and not the production of an agricultural product for sale, it is not an agricultural end-use. Examples of activities that are agricultural services include animal boarding and training, agricultural research, brokering or resale of agricultural products, farming at correctional facilities, experimental or educational farming, and fish hatcheries for wild release. Other activities which do not involve the production of an agricultural product for sale include cemetery, golf course, and park landscaping, wildlife habitat flooding, and zoo activities.

2. PACKING AND PACKAGING

Qualifying packing and packaging are defined herein as otherwise qualifying activities performed by the first entity or individual to pack or package the agricultural product, following the first sale and before any subsequent sale, transfer of control of, or title to the agricultural product.

3. QUALIFYING ACTIVITIES PERFORMED BY NONPROFIT COOPERATIVES

This applicability criteria treats all otherwise qualifying activities performed by cooperatives as though they were performed before the first sale, transfer of control of, or title to the agricultural product. Cooperatives may engage in any qualifying activity that would be permitted by the producer of the agricultural product. In order to be a qualifying cooperative, the association must be a nonprofit cooperative association organized and functioning under, and in compliance with, the California Food & Agriculture Code.

4. �“FIRST SALE�” DEFINED

The first sale of, transfer of control of, or title to the agricultural product and refers to the demarcation between agricultural and non-agricultural end-uses. It applies to all activities other than qualifying packing and packaging activities described above in Section D(2) and activities performed by qualifying nonprofit cooperatives described above in Section D(3).

(N) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

(N)




DEFINITIONS

(Continued)



D. Guidelines for Applying the Applicability Criteria (Cont�’d.)

5. Processing

Any activity that qualifies the customer as a Processor as defined in the California Food & Agriculture Code § 55407 and any activity defined as Processing under the California Food & Agriculture Code § 42519 shall not qualify as an agricultural end-use under this applicability criteria, unless the specific product and process is identified as an agricultural end-use in Section C above.

Food & Agriculture Code § 55407 �– �“Processor�” means any person that is engaged in the business of processing or manufacturing any farm product, that solicits, buys, contracts to buy, or otherwise takes title to, or possession or control of, any farm product from the producer of the farm product for the purpose of processing or manufacturing it and selling, reselling, or redelivering it in any dried, canned, extracted, fermented, distilled, frozen, eviscerated, or other preserved or processed form. It does not, however, include any retail merchant that has a fixed or established place of business in this state and does not sell at wholesale any farm product which is processed or manufactured by him.

Food & Agriculture Code § 42519 �– �“Processing�” means canning, preserving, or fermenting, which materially alters the flavor, keeping quality, or any other property, the extracting of juices or other substances, or the making of any substantial change of form. It does not include refrigeration at temperatures which are above the freezing point nor any other treatment which merely retards or accelerates the natural processes of ripening or decomposition.

6. Processing operation

If any part of an operation processes an agricultural product, no portion of the operation will qualify as an agricultural end-use under this applicability statement. In addition, no activity or operation performed after processing of the agricultural product has occurred may qualify as an agricultural end-use.

7. Agricultural product

An agricultural product is defined as the crop yielded at the conclusion of the harvest operation. If the first primary wholesale product produced following the harvest operation is a processed item, such as oil, juice, seeds, or similar product, such processing is not an agricultural end-use under this Applicability Criteria.

(N) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

(N)




DEFINITIONS

(Continued)



D. Guidelines for Applying the Applicability Criteria (Cont�’d.)

8. Harvest operation

Harvest operation includes those activities most commonly performed in the field to yield the crop in PG&E service territory, as measured on a per tonnage basis.

E. Requests for Agricultural Rates and Complaints before the CPUC Regarding Agricultural Rate Applicability

1. If, after March 2, 2006, a customer submits a written claim to PG&E for agricultural rates, any applicable Rule 17.1 adjustments will be determined on the basis of this applicability statement.

2. If, on or before March 2, 2006, a customer submitted a written claim to PG&E for agricultural rates, any applicable Rule 17.1 adjustments will be determined as follows:

(a) For the pre-March 2, 2006 time period, on the basis of the previous agricultural applicability statement.

(b) For the post-March 2, 2006 time period, on the basis of this applicability statement.

QUALIFIED CONTRACTOR/SUBCONTRACTOR (QC/S): An applicant's contractor or subcontractor who:

1) Is licensed in California for the appropriate type of work such as, but not limited to, electrical and general;

2) Employs electric workmen properly qualified (Qualified Electrical Worker, Qualified Person, etc.) as defined in State of California High Voltage Safety Orders (Title 8, Chapter 4, Subchapter 5, Group 2); and

3) Complies with applicable laws such as, but not limited to, Equal Opportunity Regulations, OSHA and EPA.

(N) | | | | | | | | | | | | | | | | | | | | | | |

(N)

(L) | | | | | | | | | |

(L)




DEFINITIONS

(Continued)


RATE REDUCTION BONDS: Securities to be issued pursuant to AB 1890, the California electric industry restructuring legislation, the proceeds of which are used to finance transition costs in an amount sufficient to provide a legislated 10 percent rate reduction to residential and small commercial customers during the transition period.

(N) | |

(N)

RATE SCHEDULE: One or more tariff sheets(s) setting forth the charges and conditions for a particular class or type of service in a given area or location. A rate schedule includes all the wording on the applicable tariff sheet(s), such as Schedule number, title, class of service, applicability, territory, rates, conditions, and references to rules.

RECREATIONAL VEHICLE (RV): As defined in the California Health and Safety Code, a motor home, slide-in camper, park trailer, or camping trailer, with or without motive power, designed for human habitation for recreational or emergency occupancy.

(T) (T)

RECREATIONAL VEHICLE (RV) PARK: An area or tract of land or a separate designated section within a mobile home park where one or more lots are occupied by owners or users of recreational vehicles.

(T)

(L)




DEFINITIONS

(Continued)


RESIDENTIAL CUSTOMER: Class of customers whose dwellings are single-family units, multi-family units, mobilehomes or other similar living establishments (see Residential Dwelling Unit and Residential Hotel).

(N) |

(N)

RESIDENTIAL DWELLING UNIT: A room or group of rooms, such as a house, a flat, or an apartment, which provides complete family living facilities in which the occupant(s) normally cooks meals, eats, sleeps, and carries on the household operations incidental to domestic life.

(L) | |

(L)

RESIDENTIAL HOTEL: A hotel establishment which provides lodging as a primary or permanent residence and has at least 50 percent of the units or rooms leased for a minimum period of one month and said units are occupied for nine months of the year. Residential hotels do not include establishments such as guest or resort hotels, resort motels or resort ranches, tourist camps, recreational vehicle parks, half-way houses, rooming houses, boarding houses, dormitories, rest homes, military barracks, or a house, apartment, flat or any residential unit which is used as a residence by a single family or group of persons.

RULES: Tariff sheets which cover the application of all rates, charges, and services, when such applicability is not set forth in and as part of the rate schedules.

(L)




DEFINITIONS

(Continued)

Advice Letter No: 1764-E Issued by Date Filed May 7, 1998Decision No. Thomas E. Bottorff Effective June 16, 1998 Vice President Resolution No. 25C1 Rates Account Services

SCHEDULED METER READING DATE: The date PG&E has scheduled a Customer�’s meter to be read for the purposes of ending the current billing cycle and beginning a new one. PG&E�’s meter reading schedule is published annually, but is subject to periodic change.

SCHEDULING COORDINATOR: An entity meeting requirements as set forth by the Commission, FERC, and these tariffs.

SERVICE ACCOUNT: Same as �“Account.�”

SINGLE-CUSTOMER SUBSTATION: A substation owned by PG&E and dedicated to serve a specific customer. Substations transform electricity from transmission to distribution voltage.

SMALL CUSTOMER: Customers on demand-metered schedules (A-10 and E-19V), with less than 20 kW maximum billing demand per meter for at least 9 billing periods during the most recent 12 month period; or (2) any customer on a non-demand metered schedule (A-1 and A-6); or (3) any customer on a residential rate schedule.

(T)




DEFINITIONS

(Continued)

Advice Letter No: 2877-E Issued by Date Filed August 4, 2006Decision No. 06-07-027 Brian K. Cherry Effective September 1, 2006 Vice President Resolution No. 26C1 Regulatory Relations

SMARTMETER�™: Trademark used by PG&E with permission of trademark owner for use in conjunction with PG&E's Advanced Metering Infrastructure (AMI) project (approved by the Commission in D.06-07-027) and in conjunction with the marketing of any or all related goods and services of PG&E associated with AMI.

(N) | |

(N)

SUBMETERING: Where the master-metered customer installs, owns, maintains, and reads the meters for billing the tenants in accordance with Rule 18.

TARIFFS: The entire body of effective rates, rentals, charges, and rules, collectively, of PG&E, including title page, preliminary statement, rate schedules, rules, sample forms, service area maps, and list of contracts and deviations.

TARIFF SHEET: An individual sheet of the tariff schedules.

TIME-OF-USE (TOU): Rate option that prices electricity according to the season or time of day that it is used. Such usage is aggregated into discrete time periods are called TOU periods and are as specified within PG&E rate schedules.




DEFINITIONS


TRANSMISSION LOAD CUSTOMER: A PG&E electric customer, interconnected to PG&E's power system at a transmission level voltage, who has no generation of its own paralleled with the PG&E system and is not interconnected with any generation source other than PG&E.

(L) | |

(L)

TRUST TRANSFER AMOUNT (TTA) CHARGE: A non-bypassable, separate charge that is authorized by the Commission to be charged to residential and small commercial customers to allow PG&E to recover financed transition costs and the costs of providing, recovering, financing or refinancing transition costs, including the costs of issuing, servicing, and retiring Rate Reduction Bonds. Also, commonly known as the Fixed Transition Amount (FTA ) Charge.

(N) | | | |

(N)

UTILITY: Pacific Gas and Electric Company (PG&E). (L)

UTILITY USERS TAX: A tax imposed by local governments on PG&E's customers. PG&E is required to bill customers within the city or county for the taxes due, collect the taxes from customers, and then pay the taxes to the city or county. The tax is calculated as a percentage of the charges billed by PG&E for energy use.

(L) | |

(L)

Revised Cal. P.U.C. Sheet No. 14329-E* Cancelling Revised Cal. P.U.C. Sheet No. 13273-E*



SUPPLY TO SEPARATE PREMISES AND SUBMETERING OF ELECTRIC ENERGY

(Continued)

Advice Letter No: 1649-E Issued by Date Filed February 4, 1997Decision No. Gordon R. Smith Effective February 4, 1997 Vice President Resolution No. 1C1 and Chief Financial Officer

A. SEPARATE METERING

Separate premises, even though owned by the same customer, will not be supplied through the same meter, except as may be specifically provided for in the applicable rate schedule.

B. OTHER USES OR PREMISES

A customer shall not furnish or use electricity received from PG&E upon premises, or for purposes, other than those specified in his application for service.

C. FURNISHING AND METERING OF ELECTRICITY

1. RESIDENTIAL SERVICE

PG&E will furnish and meter electricity to each individual residential dwelling unit, except:

a. Where electricity is furnished under a rate schedule that specifically provides for resale service; or

b. Where a customer, or his predecessors in interest on the same premises, was a customer on June 13, 1978, receiving electricity through a single meter to an apartment house, mobile home park, or other multifamily accommodation, and the cost of electricity is absorbed in the rental for the individual dwelling unit, there is no separate identifiable charge by such customer to the tenants for electricity, and the rent does not vary with electric consumption; or

c. Where a customer or his predecessors in interest on the same premises was a customer on December 14, 1981, and submeters and furnishes electricity to residential tenants at the same rates and charges that would be applicable if the user were purchasing such electricity directly from PG&E; or

d. Where a mobile home park or manufactured housing community developer, owner or operator who installs, owns and operates the electric distribution system within the park, submeters and furnishes electricity to residential tenants in each occupancy, charges the same rates that would be applicable if the user were purchasing such electricity directly from PG&E, unless construction of a new mobilehome park, or manufactured housing community commenced after January 1, 1997.

(T)

(T) (T)





(Continued)


C. FURNISHING AND METERING OF ELECTRICITY (Cont'd.)

1. RESIDENTIAL SERVICE (Cont�’d.)

e. Nothing in this section shall prevent PG&E from furnishing separately-metered service to electric equipment used in common by residential tenants or owners.

2. NONRESIDENTIAL SERVICE

PG&E will furnish and meter electricity to each individual nonresidential premises or space, except:

a. Where electricity is furnished under a rate schedule that specifically provides for resale service; or

b. Where a customer is receiving electricity through a single meter and the cost of electricity is absorbed in the rental for the individual premises or spaces, there is no separate identifiable charge by such customer to the tenants for electricity, and the rent does not vary with electric consumption; or where all of the following conditions are met:

1) Service is supplied to a high rise building* which is owned or managed by a single entity on a single premises; and

2) Where a master-meter customer installs, owns, and maintains electric submeters on its existing building�’s distribution system for cost allocation of dynamic pricing and/or conservation incentive purposes the cost of electricity allocated to the commercial building tenants will be billed at the same rate as the master meter billed by PG&E under the CPUC approved rate schedule servicing the master meter.

c. Where, in the sole opinion of PG&E, it is impractical for PG&E to meter individually each premises or space. In such a case, PG&E will meter those premises or spaces that it is practical to meter, if any.

d. Where the Commission has authorized PG&E to supply electric service through a single meter and to furnish service to nonresidential tenants on the same basis as in 1.c. above.

(T)

(N) | | | | | | |

(N)

_______________

* See Rule 1 for definition of High Rise Building.

(N)





(Continued)

Advice Letter No: 1472-E Issued by Date Filed May 17, 1994Decision No. Gordon R. Smith Effective May 17, 1994 Vice President Resolution No. 3C1 and Chief Financial Officer


3. MARINAS AND SMALL CRAFT HARBORS

Notwithstanding any other provision of this rule, PG&E will furnish electrical service to the master-meter customer at a privately or publicly owned marina or small craft harbor. The master-meter customer may submeter individual slips or berths at the marina or harbor but may not submeter any land-based facility or tenant.

If the master-meter customer submeters and furnishes electricity to individual slips or berths, the rates and charges to the user must not exceed those that would apply if the user were purchasing such electricity directly from PG&E.

4. RECREATIONAL VEHICLE (RV) PARKS

PG&E will provide electric service to all spaces in an RV park through one meter unless the condition under c. below applies. PG&E will not provide individual metering to each RV space.

Under no circumstances shall an RV park owner/operator install submeters and bill the tenants for submetered energy use unless condition a., b., or c. below applies and the provisions of Section D. below are met:

a. Where the RV park owner/operator installed a submetering system prior to May 15, 1962.

b. Where the RV park owner/operator rents all of the RV spaces on a prepaid monthly basis to RV units used as permanent residences and qualifies for service under Schedule ESR.

c. Where a master-metered RV park owner/operator rents RV spaces on a prepaid monthly basis to permanent-residence RV units and on a daily/weekly basis to transient RV units and arranges the electric distribution system in accordance with PG&E's applicable tariffs so that all electricity to the permanent-residence RV spaces is supplied through a separate PG&E meter. In this situation, only the separately metered portion of the RV park where all of the spaces are rented on a prepaid monthly basis to permanent-residence RV units can be submetered and would qualify for service under Schedule ESR.

(T)





Advice Letter No: 1439-E Issued by Date Filed June 30, 1993Decision No. 93-06-087 Gordon R. Smith Effective July 15, 1993 Vice President Resolution No. 4C1 and Chief Financial Officer


4. RECREATIONAL VEHICLE (RV) PARKS (Cont'd.)

Where the master-metered RV park owner/operator does not submeter the electric service to the RV spaces, such energy use shall be absorbed in the tenant's rental charge which cannot vary month to month.

Where the master-metered RV park owner/operator installed submeters prior to May 15, 1962 (see condition a. above), the owner/operator may bill the RV park tenants for such energy use, provided the billings are calculated using the same rate schedules PG&E uses for billing its customers.

Where the master-metered RV park owner/operator submeters the electric service to the permanent-residence RV park spaces under Schedule ESR (see conditions b. and c. above), the owner/operator will bill the prepaid monthly tenants for such energy use using the same rate schedules PG&E uses for billing its residential customers.

D. TESTING OF SUBMETERS

As a condition of service for submetering, where electric energy is furnished in accordance with Paragraphs C.1., C.2., C.3, and C.4. above, customers using submeters as a basis for charges for electricity shall submit to PG&E certification by a meter testing laboratory, satisfactory to PG&E, as to the accuracy of the submeters upon initial installation of such submeters, or for existing submeters upon request of PG&E. As a further condition of service for submetering, the customer shall agree that he will be governed by PG&E's Rule 17, Meter Tests and Adjustment of Bills for Meter Error, with the exception that the word "subcustomer" be substituted for "customer" and the words "Utility's customer" be substituted for "Company." As a further condition of service for submetering, the customer shall agree that PG&E may inspect and examine customer's billing procedures from time to time to determine that such service is made in accordance with this rule or as otherwise may be authorized by the Commission.

E. In the event such energy is furnished or resold otherwise than as provided for above, PG&E may either discontinue service to the customer or, where feasible, furnish electric energy directly to the subcustomer in accordance with PG&E's tariff on file with the Commission.

(N) | | | | | | | | | | | | | |

(N)

(T)

Attachment B – PG&E Rate Schedules E-19 and E 20



ELECTRIC SCHEDULE E-19 Sheet 1

MEDIUM GENERAL DEMAND-METERED TOU SERVICE

(Continued)


CONTENTS: This rate schedule is divided into the following sections:

1. Applicability (D) 2. Territory 12. Common-Area Accounts (T) 3.

4. 5.

Rates Metering Requirements Definition Of Service Voltage

13. 14. 15.

Voluntary Service Provisions Billing Fixed Transition Amount

| | |

6. 7.

Definition Of Time Periods Power Factor Adjustments

16. CARE Discount for Nonprofit Group-Living Facilities

(T)

8. 9. 10. 11.

Charges For Transformer and Line Losses Standard Service Facilities Special Facilities Arrangements For Visual-Display Metering

17. 18. 19.

Electric Emergency Plan Rotating Block Outages Standby Applicability Department of Water Resources Bond Charge

(T)

(T) (T)

1. APPLICABILITY: Initial Assignment: A customer must take service under Schedule E-19 if: (1) the customer's load does not meet the Schedule E-20 requirements, but, (2) the customer's maximum billing demand (as defined below) has exceeded 499 kilowatts for at least three consecutive months during the most recent 12-month period (referred to as Schedule E-19). If 70 percent or more of the customer's energy use is for agricultural end-uses, the customer will be served under an agricultural schedule. Schedule E-19 is not applicable to customers for whom residential service would apply, except for single-phase and polyphase service in common areas in a multifamily complex (see Common-Area Accounts section).

Customer accounts which fail to qualify under these requirements will be evaluated for transfer to service under a different applicable rate schedule.

The provisions of Schedule S�—Standby Service Special Conditions 1 through 6 shall also apply to customers whose premises are regularly supplied in part (but not in whole) by electric energy from a nonutility source of supply. These customers will pay monthly reservation charges as specified under Section 1 of Schedule S, in addition to all applicable Schedule E-19 charges. Exemptions to standby charges are outlined in the Standby Applicability Section of this rate schedule.

Voluntary E-19 Service: This schedule is available on a voluntary basis for customers with maximum billing demands less than 500 kW. Customers voluntarily taking service on this schedule are subject to all the terms and conditions below, unless otherwise specified in Section 14.





(Continued)


1. APPLICABILITY: (Cont�’d.)

Depending upon whether or not an Installation or Processing Charge applied prior to May 1, 2006, the customer will be served under one of these rates under Schedule E-19:

Rate V: Applies to customers who were on Rate V as of May 1, 2006.

Rate W: Applies to customers who were on Rate W as of May 1, 2006.

Rate X: Applies to customers who were on Rate X as of May 1, 2006 or who qualify for the voluntary provisions of this tariff and enroll on E-19 on or after May 1, 2006.

Transfers Off of Schedule E-19: If a customer�’s maximum demand has failed to exceed 499 kilowatts for 12 consecutive months, PG&E will transfer that customer�’s account to voluntary E-19 service or to a different applicable rate schedule. After being placed on this schedule due to the 200 kW or greater provisions of this schedule, customers who fail to exceed 199 kilowatts for 12 consecutive months may elect to stay on the time-of-use provisions of this schedule or elect an applicable non-time-of-use rate schedule or alternate time-of-use rate schedule.

Assignment of New Customers: If a customer is new and PG&E believes that the customer�’s maximum demand will be 500 through 999 kilowatts and that the customer should not be served under a time-of-use agricultural schedule, PG&E will serve the customer�’s account under Schedule E-19.

Definition of Maximum Demand: Demand will be averaged over 15-minute intervals for customers whose maximum demand exceeds 499 kW. �“Maximum demand�” will be the highest of all the 15-minute averages for the billing month. If the customer�’s use of electricity is intermittent or subject to severe fluctuations, a 5-minute interval may be used. If the customer has any welding machines, the diversified resistance welder load, calculated in accordance with Section J of Rule 2, will be considered the maximum demand if it exceeds the maximum demand that results from averaging the demand over 15-minute intervals. The customer�’s maximum-peak-period demand will be the highest of all the 15-minute averages for the peak period during the billing month. (See Section 6 for a definition of �“Peak-Period.�”) See Section 14 for the definition of maximum demand for customers voluntarily selecting E-19.

Solar Pilot Program: Customers who exceed 499 kW for at least three consecutive months during the most recent 12-month period and must otherwise take service on mandatory Schedule E-19 may elect service under Schedule A-6 under the terms outlined in the Solar Pilot Program section of Schedule A-6.

(N) | |

(N)





(Continued)



Standby Demand: For customers for whom Schedule S�—Standby Service Special Conditions 1 through 6 apply, standby demand is the portion of a customer�’s maximum demand in any month caused by nonoperation of the customer�’s alternate source of power, and for which a demand 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 capacity charge (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&E the amount of standby demand in any month. This may be done by submitting to PG&E a completed Electric Standby Service Log Sheet (Form 79-726).

2. TERRITORY: This rate schedule applies everywhere PG&E provides electricity service.

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

Only customers that received the benefit of the 10 percent rate reduction prior to January 1, 2004, and who pay the Fixed Transition Amount (FTA), shall be subject to the FTA and the Rate Reduction Bond Memorandum Account (RRBMA) rates.

(T)





(Continued)

Advice Letter No: 3238-E-B Issued by Date Filed April 29, 2008Decision No. 08-04-025,08-04-026 Brian K. Cherry Effective May 1, 200808-02-018,08-04-008,07-09-004 Vice President Resolution No. 4C15 Regulatory Relations

3. Rates: (Cont�’d.)

TOTAL RATES

Total Customer/Meter Charge Rates Secondary

Voltage Primary Voltage

TransmissionVoltage

Customer Charge Mandatory E-19 ($ per meter per day) $13.55236 $19.71253 $39.42505 Customer Charge Rate V ($ per meter per day) $4.11992 $4.11992 $4.11992 Customer Charge Rate W ($ per meter per day) $3.97799 $3.97799 $3.97799 Customer Charge Rate X ($ per meter per day) $4.11992 $4.11992 $4.11992 Optional Meter Data Access Charge ($ per meter per day) $0.98563 $0.98563 $0.98563

Total Demand Rates ($ per kW)

Maximum Peak Demand Summer $11.41 (R) $10.30 (R) $7.94 (R) Maximum Part-Peak Demand Summer $2.61 (R) $2.36 (R) $1.80 (R) Maximum Demand Summer $6.90 (I) $5.90 (I) $3.98 (I) Maximum Part-Peak Demand Winter $1.00 $0.75 $0.00 Maximum Demand Winter $6.90 (I) $5.90 (I) $3.98 (I)

Total Energy Rates ($ per kWh)

FTA Peak Summer $0.13050 (R) $0.13006 (R) $0.09597 (R) Part-Peak Summer $0.08927 | $0.08744 | $0.07684 | Off-Peak Summer $0.07245 | $0.06907 | $0.06541 | Part-Peak Winter $0.07947 | $0.07511 | $0.06991 | Off-Peak Winter $0.06996 (R) $0.06575 (R) $0.06201 (R)

Non-FTA Peak Summer $0.13219 (R) $0.13175 (R) $0.09766 (R) Part-Peak Summer $0.09096 | $0.08913 | $0.07853 | Off-Peak Summer $0.07414 | $0.07076 | $0.06710 | Part-Peak Winter $0.08116 | $0.07680 | $0.07160 | Off-Peak Winter $0.07165 (R) $0.06744 (R) $0.06370 (R) Average Rate Limiter ($/kWh in summer months) $0.20692 (R) $0.20692 (R) Power Factor Adjustment Rate ($/kWh/%) $0.00005 $0.00005 $0.00005

Total bundled service charges shown on customers�’ bills are unbundled according to the component rates shown below.





(Continued)


3. Rates: (Cont�’d.)

UNBUNDLING OF TOTAL RATES Customer/Meter Charge Rates: Customer and meter charge rates provided in the Total Rates section above are assigned entirely to the unbundled distribution component.

Demand Rates by Components ($ per kW) Secondary


Transmission Voltage

Generation: Maximum Peak Demand Summer $7.93 (R) $7.63 (R) $7.94 (R) Maximum Part-Peak Demand Summer $1.69 (R) $1.64 (R) $1.80 (R) Maximum Demand Summer $0.00 $0.00 $0.00 Maximum Part-Peak Demand Winter $0.00 $0.00 $0.00 Maximum Demand Winter $0.00 $0.00 $0.00 Distribution:** Maximum Peak Demand Summer $3.48 (I) $2.67 (I) $0.00 Maximum Part-Peak Demand Summer $0.92 $0.72 $0.00 Maximum Demand Summer $4.15 (I) $3.15 (I) $1.23 (I) Maximum Part-Peak Demand Winter $1.00 $0.75 $0.00 Maximum Demand Winter $4.15 (I) $3.15 (I) $1.23 (I) Transmission Maximum Demand* $2.97 $2.97 $2.97 Reliability Services Maximum Demand* ($0.22) ($0.22) ($0.22) Energy Charges by Components ($ per kWh) Generation: Peak Summer $0.09994 (R) $0.10241 (R) $0.07752 (R) Part-Peak Summer $0.06562 | $0.06532 | $0.05839 | Off-Peak Summer $0.05110 | $0.04880 | $0.04696 | Part-Peak Winter $0.05650 | $0.05357 | $0.05146 | Off-Peak Winter $0.04829 (R) $0.04525 (R) $0.04356 (R) Distribution**: Peak Summer $0.01151 (I) $0.00923 (I) $0.00000 Part-Peak Summer $0.00460 | $0.00370 | $0.00000 Off-Peak Summer $0.00230 | $0.00185 | $0.00000 Part-Peak Winter $0.00392 | $0.00312 | $0.00000 Off-Peak Winter $0.00262 (I) $0.00208 (I) $0.00000 Transmission Rate Adjustments* (all usage) ($0.00030) ($0.00030) ($0.00030) Public Purpose Programs (all usage) $0.01022 $0.00959 $0.00962 Nuclear Decommissioning (all usage) $0.00027 $0.00027 $0.00027 Competition Transition Charge (all usage) $0.00260 (R) $0.00260 (R) $0.00260 (R) Energy Cost Recovery Amount (all usage) $0.00318 $0.00318 $0.00318 DWR Bond (all usage) $0.00477 $0.00477 $0.00477 Fixed Transition Amount (all usage, when applicable)

$0.00000 $0.00000 $0.00000

Rate Reduction Bond Memorandum Account** (all usage, when applicable)

($0.00169) ($0.00169) ($0.00169)

_______________

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

** Distribution and applicable RRBMA charges are combined for presentation on customer bills.





(Continued)


3. RATES: (Cont�’d.)

a. TYPES OF CHARGES: The customer�’s monthly charge for service under Schedule E-19 is the sum of a customer charge, demand charges, and energy charges:

�– The customer charge is a flat monthly fee.

�– This schedule has three demand charges, a maximum-peak-period-demand charge, a maximum part-peak-period and a maximum-demand charge. The maximum-peak-period-demand charge per kilowatt applies to the maximum demand during the month�’s peak hours, the maximum part-peak-period demand charge per kilowatt applies to the maximum demand during the month�’s part-peak hours, and the maximum demand charge per kilowatt applies to the maximum demand at any time during the month. The bill will include all of these demand charges. (Time periods are defined in Section 6.)

�– The energy charge is the sum of the energy charges from the peak, partial-peak, and off-peak periods. The customer pays for energy by the kilowatt-hour (kWh), and rates are differentiated according to time of day and time of year.

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

�– The monthly charges may be increased or decreased based upon the power factor. (See Section 7.)

�– As shown on the rate chart, which set of customer, demand, and energy charges is paid depends on the level of the customers maximum demand and the voltage at which service is taken. Service voltages are defined in Section 5 below.

(T)

(D)





(Continued)



b. AVERAGE RATE LIMITER (applies to bundled service only): If the customer takes service on Schedule E-19 in either the secondary or primary voltage class, bills will be controlled by a �“rate limiter�” during the summer months. The bill will be reduced if necessary so that the average rate paid for all demand and energy charges during a summer month does not exceed the average rate limiter shown on this Schedule. This provision will not apply if the customer has elected to receive separate billing for back-up and maintenance service under Special Condition 8 of Schedule S.

Reductions in revenue resulting from application of the average rate limiter will be reflected as reduced distribution amounts for billing purposes.

(T)

Original Cal. P.U.C. Sheet No. 24886-E Cancelling Revised Cal. P.U.C. Sheet No. 22763-E**




(Continued)

Advice Letter No: 2810-E-A Issued by Date Filed April 14, 2006Decision No. 05-11-005 Thomas E. Bottorff Effective May 1, 2006 Senior Vice President Resolution No. 8C2 Regulatory Relations

4. METERING REQUIRE-MENTS:

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

Customers with a maximum demand of 200 kW or greater for three consecutive months must have an interval data meter that can be read remotely by PG&E. A Meter Data Management Agent (MDMA) may also read the customer�’s meter on behalf of the customer�’s Energy Service Provider (ESP) if a customer is receiving Direct Access Service.

For bundled service customers with a maximum demand of 200 kW or greater for three consecutive months, PG&E will provide and install the interval data meter at no additional cost to the customer. After the interval meter is installed, the customer must take service on a time-of-use schedule. The installation of an interval data meter for customers taking service under the provisions of Direct Access is the responsibility of the customer�’s Energy Service Provider, or their Agent, and must be installed in accordance with Electric Rule 22.

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

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

(D)

(T) (T)

(T) | |

(T)

(T)

(L) |

(L)

5. DEFINITION OF SERVICE VOLTAGE:

The following defines the three voltage classes of Schedule E-19 rates. Standard Service 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 volts or 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 customer substation�” or without transformation from PG&E�’s serving distribution system at one of the standard primary voltages specified in PG&E�’s Electric Rule 2, Section B.1.

c. Transmission: This is the voltage class if the customer is served without transformation from PG&E�’s serving transmission system at one of the standard transmission voltages specified in PG&E�’s Rule 2, Section B.1.





(Continued)


6. DEFINITION OF TIME PERIODS:

Times of the year and times of the day are defined as follows:

SUMMER Period A (Service from May 1 through October 31):

Peak: 12:00 noon to 6:00 p.m. Monday through Friday (except holidays)

Partial-peak: 8:30 a.m. to 12:00 noon Monday through AND 6:00 p.m. to 9:30 p.m. Friday (except holidays)

Off-peak: 9:30 p.m. to 8:30 a.m. Monday through Friday All day Saturday, Sunday, and holidays

WINTER Period B (service from November 1 through April 30):

Partial-Peak: 8:30 a.m. to 9:30 p.m. Monday through Friday (except holidays)

Off-Peak: 9:30 p.m. to 8:30 a.m. Monday through Friday (except holidays) All day Saturday, Sunday, and holidays

HOLIDAYS: �“Holidays�” for the purposes 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.

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.

CHANGE FROM SUMMER TO WINTER OR WINTER TO SUMMER: When a billing month includes both summer and winter days, PG&E will calculate demand charges as follows. It will consider the applicable maximum demands for the summer and winter portions of the billing month separately, calculate a demand charge for each, and then apply the two according to the number of billing days each represents.

7. POWER FACTOR ADJUST-MENTS:

Bills will be adjusted based on the power factor for all customers except those selecting voluntary E-19 service. The power factor is computed from the ratio of lagging reactive kilovolt-ampere-hours to the kilowatt-hours consumed in the month. Power factors are rounded to the nearest whole percent.

The rates in this rate schedule are based on a power factor of 85 percent. If the average power factor is greater than 85 percent, the total monthly bill will be reduced by the product of the power factor rate and the kilowatt-hour usage for each percentage point above 85 percent. If the average power factor is below 85 percent, the total monthly bill will be increased by the product of the power factor rate and the kilowatt-hour usage for each percentage point below 85 percent.

Power factor adjustments will be assigned to distribution for billing purposes.

(D)





(Continued)


8. CHARGES FOR TRANS-FORMER AND LINE LOSSES:

The demand and energy meter readings used in determining the charges will be adjusted to correct for transformation and line losses in accordance with Section B.4 of Rule 2.

9. STANDARD SERVICE FACILITIES:

If PG&E must install any new or additional facilities to provide the customer with service under this schedule the customer may have to pay some of the cost. Any advance necessary and any monthly charge for the facilities will be specified in a line extension agreement. See Rules 2, 15, and 16 for details. This section does not apply to customers voluntarily taking service under Schedule E-19.

Facilities installed to serve the customer may be removed when service is discontinued. The customer will then have to repay PG&E for all or some of its investment in the facilities. Terms and conditions for repayment will be set forth in the line extension agreement.

10. SPECIAL FACILITIES:

PG&E will normally install only those standard facilities it deems necessary to provide service under this schedule. If the customer requests any additional facilities, those facilities will be treated as �“special facilities�” in accordance with Section I of Rule 2.

11. ARRANGE-MENTS FOR VISUAL-DISPLAY METERING:

If the customer wishes to have visual-display metering equipment in addition to the regular metering equipment, and the customer would like PG&E to install that equipment, the customer must submit a written request to PG&E. PG&E will provide and install the equipment within 180 days of receiving the request. The visual-display metering equipment will be installed near the present metering equipment. The customer will be responsible for providing the required space and associated wiring.

PG&E will continue to use the regular metering equipment for billing purposes.

(D)





(Continued)


12. COMMON- AREA ACCOUNTS:

Common-area accounts that are separately metered by PG&E and which took electric service from PG&E on or prior to January 16, 2003, have a one-time opportunity to return to a residential rate schedule from April 1, 2004 to May 31, 2004, by notifying PG&E in writing.

In the event that the CPUC substantially amends any or all of PG&E�’s commercial or residential rate schedules, the Executive Council of Homeowners (ECHO) can direct PG&E to begin an optional second right-of-return period lasting 105 days. However, if this occurs prior to the April 1, 2004 to May 31, 2004, time period, the ECHO directed right of return period will be the only window for returning to a residential schedule.

Newly constructed common-areas that are separately metered by PG&E and which first took electric service from PG&E after January 16, 2003, have a one-time opportunity to transfer to a residential rate schedule during a two-month window that begins 14 months after taking service on a commercial rate schedule. This must be done by notifying PG&E in writing. These common-area accounts have an additional opportunity to return to a residential schedule in the event that ECHO directs PG&E to begin a second right-of-return period.

Only those common-area accounts taking service on Schedule E-8 prior to moving to this tariff may return to Schedule E-8.

Common-area accounts are those accounts that provide electric service to Common Use Areas as defined in Rule 1.

(T)





(Continued)


13. VOLUNTARY SERVICE PROVISIONS:

Customers voluntarily taking service on Schedule E-19 (see Applicability Section) shall be governed by all the terms and conditions shown in Sections 1 through 12, unless different terms and conditions are shown below.

a. DEFINITION OF MAXIMUM DEMAND: Demand will be averaged over 15-minute intervals except, in special cases. �“Maximum demand�” will be the highest of all 15-minute averages for the billing month.

SPECIAL CASES: (1) If the customer�’s use of energy is intermittent or subject to severe fluctuations, a 5-minute interval may be used; and (2) If the customer uses welders, the demand charge will be subject to the minimum demand charges for those welders' ratings, as explained in Section J of Rule 2.

b. REDUCED CUSTOMER CHARGE: The reduced customer charge will be assessed only if the customer is taking service under this schedule on a voluntary basis or if the customer�’s maximum billing demand has not exceeded 499 kW for 12 or more consecutive months.

c. SERVICE CONTRACTS: This rate schedule will remain in effect for at least twelve consecutive months before another schedule change is made, unless the customer�’s maximum demand has exceeded 499 kW for three consecutive months.

(T)

14. BILLING: A customer�’s bill is calculated based on the option applicable to the customer. (T)

Revised Cal. P.U.C. Sheet No. 27419-E Cancelling Revised Cal. P.U.C. Sheet No. 26951-E*




(Continued)


14. BILLING: (Cont�’d.)

Bundled Service Customers receive supply and delivery services solely from PG&E. The customer�’s bill is based on the Total Rates and Conditions set forth in this schedule.

Transitional Bundled Service Customers take transitional bundled service as prescribed 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 prescribed in Rules 22.1 and 23.1. These customers shall pay charges for transmission, transmission rate adjustments, reliability services, distribution, nuclear decommissioning, public purpose programs, the FTA (where applicable), the RRBMA (where applicable), 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) Customers purchase energy from their non-utility provider and continue receiving delivery services from PG&E. Bills are equal to the sum of charges for transmission, transmission rate adjustments, reliability services, distribution, public purpose programs, nuclear decommissioning, the FTA (where applicable), the RRBMA (where applicable), the franchise fee surcharge, and the applicable CRS. The CRS is equal to the sum of the individual charges set forth below. Exemptions to the CRS are set forth in Schedules DA CRS and CCA CRS.

(T)

DA CRS CCA CRS Energy Cost Recovery Amount Charge (per kWh) $0.00318 $0.00318 Power Charge Indifference Adjustment (per kWh) ($0.00256) (I) $0.01740 (I) DWR Bond Charge (per kWh) $0.00477 $0.00477 CTC Charge (per kWh) $0.00260 (R) $0.00260 (R) Total DA CRS (per kWh) $0.00799 $0.02795

15. FIXED TRANSITION AMOUNT:

Eligible small commercial customers that received the benefit of the 10 percent rate reduction prior to January 1, 2004, are obligated to pay a Fixed Transition Amount (FTA), also referred to as a Trust Transfer Amount (TTA), as described in Schedule E-RRB and defined in Preliminary Statement Part AS. In addition, these customers will receive the benefit of the rate reduction bond memorandum account rate.

(T)

16. CARE DISCOUNT FOR NONPROFIT GROUP-LIVING AND SPECIAL EMPLOYEE HOUSING FACILITIES:

Facilities which meet the eligibility criteria in Rule 19.2 or 19.3 are eligible for a California Alternate Rates for Energy discount under Schedule E-CARE. CARE customers are exempt from paying the DWR Bond Charge rate component. For CARE customers, no portion of the rates shall be used to pay the DWR bond charge. Generation is calculated residually based on the total rate less the sum of the following: Transmission, Transmission Rate Adjustments, Reliability Services, Distribution, Public Purpose Programs, Nuclear Decommissioning, Competition Transition Charges (CTC), Energy Cost Recovery Amount, FTA and the Rate Reduction Bond Memorandum Account Rate.

(T)





(Continued)


17. ELECTRIC EMERGENCY PLAN ROTATING BLOCK OUTAGES

As set forth in CPUC Decision 01-04-006, all transmission level customers except essential use customers, Optional Binding Mandatory Curtailment (OBMC) plan participants, net suppliers to the electrical grid, or others exempt by the Commission, are to be included in rotating outages in the event of an emergency. A transmission level customer who refuses or fails to drop load shall be added to the next rotating outage group so that the customer does not escape curtailment. If the transmission level customer fails to cooperate and drop load at PG&E's request, automatic equipment controlled by PG&E will be installed at the customer�’s expense per Electric Rule 2. A transmission level customer who refuses to drop load before installation of the equipment shall be subject to a penalty of $6/kWh for all load requested to be curtailed that is not curtailed. The $6/kWh penalty shall not apply if the customer�’s generation suffers a verified, forced outage and during times of scheduled maintenance. The scheduled maintenance must be approved by both the ISO and PG&E, but approval may not be unreasonably withheld.

(T)






18. STANDBY APPLICA- BILITY:

SOLAR GENERATION FACILITIES EXEMPTION: Customers who utilize solar generating facilities which are less than or equal to one megawatt to serve load and who do not sell power or make more than incidental export of power into PG&E�’s power grid and who have not elected service under Schedule NEM, will be exempt from paying the otherwise applicable standby reservation charges.

DISTRIBUTED ENERGY RESOURCES EXEMPTION: Any customer under a time-of-use (TOU) rate schedule using electric generation technology that meets the criteria as defined in Electric Rule 1 for Distributed Energy Resources is exempt from the otherwise applicable standby reservation charges. Customers qualifying for this exemption shall be subject to the following requirements. Customers qualifying for an exemption from standby charges under Public Utilities (PU) Code Sections 353.1 and 353.3, as described above, must take service on a TOU schedule in order to receive this exemption until a real-time pricing program, as described in PU Code 353.3, is made available. Once available, customers qualifying for the standby charge exemption must participate in the real-time program referred to above. Qualification for and receipt of this distributed energy resources exemption does not exempt the customer from metering charges applicable to TOU and real-time pricing, or exempt the customer from reasonable interconnection charges, non-bypassable charges as required in Preliminary Statement BB - Competition Transition Charge Responsibility for All Customers and CTC Procurement, or obligations determined by the Commission to result from participation in the purchase of power through the California Department of Water Resources, as provided in PU Code Section 353.7.

(T)

19. DWR BOND CHARGE:

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

(T)




SERVICE TO CUSTS WITH MAX DEMANDS OF 1000 K OR MORE

(Continued)


CONTENTS: This rate schedule is divided into the following sections:

1. Applicability 2. Territory 3. Firm Service Rates 12. Billing (T) 4.

5. Metering Requirement Definition Of Service Voltage

13. CARE Discount For Nonprofit Group-Living Facilities

(T)

6. 7. 8.

Definition Of Time Periods Power Factor Adjustments Charges For Transformer and Line Losses

14. 15.

Electric Emergency Plan Rotating Block Outages Standby Applicability

(T)

(T)

9. 10. 11.

Standard Service Facilities Special Facilities Arrangements For Visual-Display Metering

16. Department of Water Resources Bond Charge

(T)

(D)

1. APPLICABILITY: Initial Assignment: A customer is eligible for service under Schedule E-20 if the customer�’s maximum demand (as defined below) has exceeded 999 kilowatts for at least three consecutive months during the most recent 12-month period. If 70 percent or more of the customer�’s energy use is for agricultural end-uses, the customer will be served under an agricultural schedule.

Customer accounts which fail to qualify under these requirements will be evaluated for transfer to service under a different applicable rate schedule.

The provisions of Schedule S�—Standby Service Special Conditions 1 through 6 shall also apply to customers whose premises are regularly supplied in part (but not in whole) by electric energy from a nonutility source of supply. These customers will pay monthly reservation charges as specified under Section 1 of Schedule S, in addition to all applicable Schedule E-20 charges. Exemptions to standby charges are outlined in the Standby Applicability Section of this rate schedule.

Transfers Off of Schedule E-20: PG&E will review its Schedule E-20 accounts annually. A customer will be eligible for continued service on Schedule E-20 if its maximum demand has either: (1) Exceeded 999 kilowatts for at least 5 of the previous 12 billing months; or (2) Exceeded 999 kilowatts for any 3 consecutive billing months of the previous 14 billing months. If a customer�’s demand history fails both of these tests, PG&E will transfer that customer�’s account to service under a different applicable rate schedule.

Assignment of New Customers: If a customer is new and PG&E believes that the customer�’s maximum demand will exceed 999 kilowatts and that the customer should not be served under a time-of-use agricultural schedule, PG&E will serve the customer�’s account under Schedule E-20.





(Continued)

Advice Letter No: 3086-E Issued by Date Filed July 17, 2007Decision No. Brian K. Cherry Effective August 16, 2007 Vice President Resolution No. 2C1 Regulatory Relations


Definition of Maximum Demand: Demand will be averaged over 15-minute intervals. �“Maximum demand�” will be the highest of all the 15-minute averages for the billing month. If the customer�’s use of electricity is intermittent or subject to severe fluctuations, a 5-minute interval may be used. If the customer has any welding machines, the diversified resistance welder load, calculated in accordance with Section J of Rule 2, will be considered the maximum demand if it exceeds the maximum demand that results from averaging the demand over 15-minute intervals. The customer�’s maximum-peak-period demand will be the highest of all the 15-minute averages for the peak period during the billing month. (See Section 6 for a definition of �“Peak-Period.�”)

Standby Demand: For customers for whom Schedule S�—Standby Service Special Conditions 1 through 6 apply, standby demand is the portion of a customer�’s maximum demand in any month caused by nonoperation of the customer�’s alternate source of power, and for which a demand 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 capacity charge (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&E the amount of standby demand in any month. This may be done by submitting to PG&E a completed Electric Standby Service Long Sheet (Form 79-726).

Solar Generation Demand Adjustment: A customer who installs a solar electric generation facility on or after January 1, 2007 may be eligible to receive a Solar Generation Demand Adjustment. A customer will qualify for a Solar Generation Demand Adjustment if both of the following conditions are met: (1) the customer�’s solar electric generating facility was installed after January 1, 2007; and (2) the solar electric generation facility reduces the customer�’s maximum demand to the point that the customer would no longer be eligible for service under this schedule. The Solar Generation Demand Adjustment will be the fixed reduction in demand as determined by PG&E from the customer�’s interconnection agreement, and will be added to the customer�’s maximum demand for the sole purpose of determining the customer�’s eligibility for Schedule E-20.

The Solar Generation Demand Adjustment does not specifically guarantee the customer�’s continued eligibility for service under this schedule nor will it be applied to the customer�’s maximum demand for purposes of calculating the monthly maximum demand charge.

The Solar Generation Demand Adjustment will terminate on December 31, 2016.

(D)

(N) | | | | | | | | | | | | | | | |

(N) 2. TERRITORY: Schedule E-20 applies everywhere PG&E provides electric service.





(Continued)


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

TOTAL RATES

Total Customer/Meter Charge Rates Secondary



Customer Charge Mandatory E-20 ($ per meter per day)

$24.64066 $32.85421 $32.70012 (I)

Optional Meter Data Access Charge ($ per meter per day)

$0.98563 $0.98563 $0.98563

Total Demand Rates ($ per kW)

Maximum Peak Demand Summer $11.10 (R) $10.51 (R) $9.64 (R) Maximum Part-Peak Demand Summer $2.47 (R) $2.43 (R) $2.16 (R) Maximum Demand Summer $7.14 (I) $5.85 (I) $3.03 Maximum Part-Peak Demand Winter $1.00 $0.64 $0.00 Maximum Demand Winter $7.14 (I) $5.85 (I) $3.03

Total Energy Rates ($ per kWh)

Peak Summer $0.12615 (R) $0.12896 (R) $0.09058 (R) Part-Peak Summer $0.08744 | $0.08754 | $0.07281 | Off-Peak Summer $0.07150 | $0.06966 | $0.06222 | Part-Peak Winter $0.07828 | $0.07535 | $0.06638 | Off-Peak Winter $0.06915 (R) $0.06629 (R) $0.05906 (R)

Average Rate Limiter ($/kWh in summer months)

$0.20184 (R) $0.20184 (R) �–

Power Factor Adjustment Rate ($/kWh/%) $0.00005 $0.00005 $0.00005 Total bundled service charges shown on customers�’ bills are unbundled according to the component rates shown below.





(Continued)



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

Demand Rates by Component ($ per kW) Secondary



Generation: Maximum Peak Demand Summer $7.58 (R) $8.21 (R) $9.64 (R) Maximum Part-Peak Demand Summer $1.56 (R) $1.80 (R) $2.16 (R) Maximum Demand Summer $0.00 $0.00 $0.00 Maximum Part-Peak Demand Winter $0.00 $0.00 $0.00 Maximum Demand Winter $0.00 $0.00 $0.00

Distribution:

Maximum Peak Demand Summer $3.52 (I) $2.30 (I) $0.00 Maximum Part-Peak Demand Summer $0.91 $0.63 | $0.00 Maximum Demand Summer $4.11 (I) $2.82 | $0.00 Maximum Part-Peak Demand Winter $1.00 $0.64 | $0.00 Maximum Demand Winter $4.11 (I) $2.82 (I) $0.00

Transmission Maximum Demand* $3.28 $3.28 $3.28 Reliability Services Maximum Demand* ($0.25) ($0.25) ($0.25) Energy Rates by Component ($ per kWh) Generation:

Peak Summer $0.09479 (R) $0.10214 (R) $0.07249 (R) Part-Peak Summer $0.06271 | $0.06516 | $0.05472 | Off-Peak Summer $0.04898 | $0.04876 | $0.04413 | Part-Peak Winter $0.05417 | $0.05348 | $0.04829 | Off-Peak Winter $0.04630 (R) $0.04524 (R) $0.04097 (R)

Distribution:

Peak Summer $0.01105 (I) $0.00739 (I) $0.00000 Part-Peak Summer $0.00442 | $0.00295 | $0.00000 Off-Peak Summer $0.00221 | $0.00147 $0.00000 Part-Peak Winter $0.00380 | $0.00244 (I) $0.00000 Off-Peak Winter $0.00254 (I) $0.00162 $0.00000

Transmission Rate Adjustments* (all usage) ($0.00032) ($0.00032) ($0.00032) Public Purpose Programs (all usage) $0.00992 $0.00920 $0.00801 Nuclear Decommissioning (all usage) $0.00027 $0.00027 $0.00027 Competition Transition Charge (all usage) $0.00249 (R) $0.00233 (R) $0.00218 (R) Energy Cost Recovery Amount (all usage) $0.00318 $0.00318 $0.00318 DWR Bond (all usage) $0.00477 $0.00477 $0.00477

_______________

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





(Continued)



a. TYPES OF CHARGES: The customer�’s monthly charge for service under Schedule E-20 is the sum of a customer charge, demand charges, and energy charges:

The customer charge is a flat monthly fee.

�– Schedule E-20 has three demand charges, a maximum-peak-period-demand charge, a maximum-part-peak-period demand charge, and a maximum-demand charge. The maximum-peak-period-demand charge per kilowatt applies to the maximum demand during the month�’s peak hours, the maximum-part-peak-demand charge per kilowatt applies to the maximum demand during the month�’s part-peak hours, and the maximum-demand charge per kilowatt applies to the maximum demand at any time during the month. The bill will include all of these demand charges. (Time periods are defined in Section 6.)

�– The energy charge is the sum of the energy charges from the peak, partial-peak, and off-peak periods. The customer pays for energy by the kilowatt-hour (kWh), and rates are differentiated according to time of day and time of year.

�– The monthly charges may be increased or decreased based upon the power factor. (See Section 7.)

�– As shown on the rate chart, which set of customer, demand, and energy charges is paid depends on the voltage at which service is taken. Service voltages are defined in Section 5 below.

b. AVERAGE RATE LIMITER (applies to bundled service only): If the customer takes service on Schedule E-20, in either the secondary or primary voltage class, bills will be controlled by a �“rate limiter�” during the summer months. The bill will be reduced if necessary so that the average rate paid for all demand and energy charges during a summer month does not exceed the rate limiter shown on this schedule. This provision will not apply if the customer has elected to receive separate billing for back-up and maintenance service pursuant to Special Condition 8 of Schedule S.

Reductions in revenue resulting from application of the average rate limiter will be reflected as reduced distribution amounts for billing purposes.

(T)

(D)

(T)

Revised Cal. P.U.C. Sheet No. 24895-E Cancelling Original Cal. P.U.C. Sheet No. 22785-E*




(Continued)

Advice Letter No: 2810-E-A Issued by Date Filed April 14, 2006Decision No. 05-11-005 Thomas E. Bottorff Effective May 1, 2006 Senior Vice President Resolution No. 6C1 Regulatory Relations

(D)

4. METERING REQUIRE-MENTS:

An interval data meter that measures and registers the amount of electricity a customer uses and can be read remotely by PG&E is required for all customers on this schedule. A Meter Data Management Agent (MDMA) may also read the customer�’s meter on behalf of the customer�’s Energy Service Provider (ESP) if a customer is receiving Direct Access Service.

For bundled service customers with a maximum demand of 200 kW or greater for three consecutive months, PG&E will provide and install the interval data meter at no cost to the customer. The installation of an interval data meter for customers taking service under the provisions of Direct Access is the responsibility of the customer�’s Energy Service Provider, or their Agent, and must be installed in accordance with Electric Rule 22.

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

(T) |

(T)

5. DEFINITION OF SERVICE VOLTAGE:

The following defines the three voltage classes of Schedule E-20 rates. Standard Service Voltages are listed in Rule 2.

a. Secondary: This is the voltage class if the service voltage is less than 2,400 volts or 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 customer substation�” or without transformation from PG&E�’s serving distribution system at one of the standard primary voltages specified in PG&E�’s Electric Rule 2, Section B.1.

c. Transmission: This is the voltage class if the customer is served without transformation at one of the standard transmission voltages specified in PG&E�’s Electric Rule 2, Section B.1.





(Continued)


6. DEFINITION OF TIME PERIODS:

Times of the year and times of the day are defined as follows:

SUMMER Period A (Service from May 1 through October 31):

Peak: 12:00 noon to 6:00 p.m. Monday through Friday (except holidays)

Partial-peak: 8:30 a.m. to 12:00 noon Monday through Friday (except holidays) AND 6:00 p.m. to 9:30 p.m.

Off-peak: 9:30 p.m. to 8:30 a.m. Monday through Friday All day Saturday, Sunday, and holidays

WINTER Period B (service from November 1 through April 30):

Partial-Peak: 8:30 a.m. to 9:30 p.m. Monday through Friday (except holidays)

Off-Peak: 9:30 p.m. to 8:30 a.m. Monday through Friday (except holidays) All day Saturday, Sunday, and holidays

HOLIDAYS: �“Holidays�” for the purposes 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.

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.

CHANGE FROM SUMMER TO WINTER OR WINTER TO SUMMER: When a billing month includes both summer and winter days, PG&E will calculate demand charges as follows. It will consider the applicable maximum demands for the summer and winter portions of the billing month separately, calculate a demand charge for each, and then apply the two according to the number of billing days each represents.

7. POWER FACTOR ADJUST-MENTS:

The bill will be adjusted based upon the power factor. The power factor is computed from the ratio of lagging reactive kilovolt-ampere-hours to the kilowatt-hours consumed in the month. Power factors are rounded to the nearest whole percent.

The rates in this rate schedule are based on a power factor of 85 percent. If the average power factor is greater than 85 percent, the total monthly bill will be reduced by the product of the power factor rate and the kilowatt-hour usage for each percentage point above 85 percent. If the average power factor is below 85 percent, the total monthly bill will be increased by the product of the power factor rate and the kilowatt-hour usage for each percentage point below 85 percent.

Power factor adjustments will be assigned to distribution for billing purposes.

(D)





(Continued)

Advice Letter No: 2623-E Issued by Date Filed February 7, 2005Decision No. 05-01-056 Karen A. Tomcala Effective March 19, 2005 Vice President Resolution No. 8C1 Regulatory Relations

(L)

8. CHARGES FOR TRANSFORMER AND LINE LOSSES:

The demand and energy meter readings used in determining the charges will be adjusted to correct for transformation and line losses in accordance with Section B.4 of Rule 2.

(T)

9. STANDARD SERVICE FACILITIES:

If PG&E must install any new or additional facilities to provide the customer with service under Schedule E-20, the customer may have to pay some of the cost. Any advance necessary and any monthly charge for the facilities will be specified in a line extension agreement. See Rules 2, 15, and 16 for details.

Facilities installed to serve the customer may be removed when service is discontinued. The customer will then have to repay PG&E for all or some of its investment in the facilities. Terms and conditions for repayment will be set forth in the line extension agreement.

(T)

10. SPECIAL FACILITIES:

PG&E will normally install only those standard facilities it deems necessary to provide service under Schedule E-20. If the customer requests any additional facilities, those facilities will be treated as �“special facilities�” in accordance with Section I of Rule 2.

(T)

11. ARRANGE-MENTS FOR VISUAL-DISPLAY METERING:

If the customer wishes to have visual-display metering equipment in addition to the regular metering equipment, and the customer would like PG&E to install that equipment, the customer must submit a written request to PG&E. PG&E will provide and install the equipment within 180 days of receiving the request. The visual-display metering equipment will be installed near the present metering equipment. The customer will be responsible for providing the required space and associated wiring.

PG&E will continue to use the regular metering equipment for billing purposes.

(T)

Revised Cal. P.U.C. Sheet No. 24179-E Cancelling Revised Cal. P.U.C. Sheet No. 22788-E 22789,22790,22




(Continued)

Advice Letter No: 2706-E-A Issued by Date Filed December 30, 2005Decision No. Thomas E. Bottorff Effective January 1, 2006 Senior Vice President Resolution No. E-39569C1 Regulatory Relations

12. NON-FIRM SERVICE PROGRAM:

As noted, the rates in the chart in Section 3 of this rate schedule apply to firm service only. ("Firm" means service where PG&E provides a "continuous and sufficient supply of electricity," as described in Rule 14.) Certain customers may also elect to receive non-firm service under Schedule E-NF.

(T)

(D)

Revised Cal. P.U.C. Sheet No. 27422-E Cancelling Revised Cal. P.U.C. Sheet No. 26959-E*




(Continued)


12. BILLING: A customer�’s bill is calculated based on the option applicable to the customer.

Bundled Service Customers receive supply and delivery services solely from PG&E. The customer�’s bill is based on the Total Rates and Conditions set forth in this schedule.

Transitional Bundled Service Customers take transitional bundled service as prescribed 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 prescribed in Rules 22.1 and 23.1. These customers shall pay charges for transmission, transmission rate adjustments, reliability services, distribution, nuclear decommissioning, public purpose programs, the FTA (where applicable), the RRBMA (where applicable), 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) Customers purchase energy from their non-utility provider and continue receiving delivery services from PG&E. Bills are equal to the sum of charges for transmission, transmission rate adjustments, reliability services, distribution, public purpose programs, nuclear decommissioning, the FTA (where applicable), the RRBMA (where applicable), the franchise fee surcharge, and the applicable CRS. The CRS is equal to the sum of the individual charges set forth below. Exemptions to the CRS are set forth in Schedules DA CRS and CCA CRS.

DA CRS Secondary



Energy Cost Recovery Amount Charge (per kWh) $0.00318 $0.00318 $0.00318 Power Charge Indifference Adjustment (per kWh) ($0.00245) (I) ($0.00229) (I) ($0.00214) (I) DWR Bond Charge (per kWh) $0.00477 $0.00477 $0.00477 CTC Rate (per kWh) $0.00249 (R) $0.00233 (R) $0.00218 (R) Total DA CRS (per kWh) $0.00799 $0.00799 $0.00799

CCA CRS Energy Cost Recovery Amount Charge (per kWh) $0.00318 $0.00318 $0.00318 Power Charge Indifference Adjustment (per kWh) $0.01751 (I) $0.01767 (I) $0.01782 (I) DWR Bond Charge (per kWh) $0.00477 $0.00477 $0.00477 CTC Rate (per kWh) $0.00249 (R) $0.00233 (R) $0.00218 (R) Total CCA CRS (per kWh) $0.02795 $0.02795 $0.02795





(Continued)


13. CARE DISCOUNT FOR NONPROFIT GROUP-LIVING AND SPECIAL EMPLOYEE HOUSING FACILITIES:

Facilities which meet the eligibility criteria in Rule 19.2 or 19.3 are eligible for a California Alternate Rates for Energy discount under Schedule E-CARE. CARE customers are exempt from paying the DWR Bond Charge. For CARE customers, no portion of the rates shall be used to pay the DWR Bond Charge. Generation is calculated residually based on the total rate less the sum of the following: Transmission, Transmission Rate Adjustments, Reliability Services, Distribution, Public Purpose Programs, Nuclear Decommissioning, Competition Transition Charge (CTC), Energy Cost Recovery Amount, FTA and the Rate Reduction Bond Memorandum Account Rate.

(T)

14. ELECTRIC EMER-GENCY PLAN ROTATING BLOCK OUTAGES:

As set forth in CPUC Decision 01-04-006, all transmission level customers except essential use customers, Optional Binding Mandatory Curtailment (OBMC) plan participants, net suppliers to the electrical grid, or others exempt by the Commission, are to be included in rotating outages in the event of an emergency. A transmission level customer who refuses or fails to drop load shall be added to the next rotating outage group so that the customer does not escape curtailment. If the transmission level customer fails to cooperate and drop load at PG&E�’s request, automatic equipment controlled by PG&E will be installed at the customer�’s expense per Electric Rule 2. A transmission level customer who refuses to drop load before installation of the equipment shall be subject to a penalty of $6/kWh for all load requested to be curtailed that is not curtailed. The $6/kWh penalty shall not apply if the customer�’s generation suffers a verified, forced outage and during times of scheduled maintenance. The scheduled maintenance must be approved by both the ISO and PG&E, but approval may not be unreasonably withheld.

(T)

15. STANDBY APPLICA-BILITY:

SOLAR GENERATION FACILITIES EXEMPTION: Customers who utilize solar generating facilities which are less than or equal to one megawatt to serve load and who do not sell power or make more than incidental export of power into PG&E�’s power grid and who have not elected service under Schedule NEM, will be exempt from paying the otherwise applicable standby reservation charges.

DISTRIBUTED ENERGY RESOURCES EXEMPTION: Any customer under a time-of-use (TOU) rate schedule using electric generation technology that meets the criteria as defined in Electric Rule 1 for Distributed Energy Resources is exempt from the otherwise applicable standby reservation charges. Customers qualifying for this exemption shall be subject to the following requirements. Customers qualifying for an exemption from standby charges under Public Utilities (PU) Code Sections 353.1 and 353.3, as described above, must take service on a TOU schedule in order to receive this exemption until a real-time pricing program, as described in PU Code 353.3, is made available. Once available, customers qualifying for the standby charge exemption must participate in the real-time program referred to above. Qualification for and receipt of this distributed energy resources exemption does not exempt the customer from metering charges applicable to TOU and real-time pricing, or exempt the customer from reasonable interconnection charges, non-bypassable charges as required in Preliminary Statement BB - Competition Transition Charge Responsibility for All Customers and CTC Procurement, or obligations determined by the Commission to result from participation in the purchase of power through the California Department of Water Resources, as provided in PU Code Section 353.7.

(T)






16. DWR BOND CHARGE:

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

(T)

Attachment C – PG&E Contacts Tenants requiring information on electricity bill calculations can find explanations on PG&E’s Web Site www.PGE.com by clicking on Business Tools and then on Explanation of Bill. Telephone support can be obtained by calling Business Customer Service at 1-800-468-4743.

http://www.pge.com/

Attachment D – California Division of Measurement Standards Contacts

Division of Measurement Standards OFFICE LOCATIONS HEADQUARTERS Division of Measurement Standards 6790 Florin Perkins Road, Suite 100 Sacramento, CA 95828 Telephone: (916) 229-3000 Fax: (916) 229-3016 Email: [email protected] NORTHERN CALIFORNIA Division of Measurement Standards 3609 Bechelli Lane, Room E Redding, CA 96002 Telephone: (530) 224-2411 Fax: (530) 224-2484 CENTRAL CALIFORNIA Division of Measurement Standards 2550 Mariposa Street, Room 3044 Fresno, CA 93721 Telephone: (559) 445-5403 Fax: (559) 445-5268 Alameda County WEIGHTS & MEASURES LOCATION 333 Fifth Street Oakland, 94607 PHONE: (510) 268-7343 FAX: (510) 444-3879 E-MAIL: [email protected] CONTRA COSTA COUNTY 2366 "A" Stanwell Circle Concord, 94520 PHONE: (925) 646-5250 FAX: (925) 646-5732

mailto:[email protected]

FRESNO COUNTY 1730 South Maple Avenue Fresno, 93702 PHONE: (559) 456-7510 FAX: (559) 456-7379 MARIN COUNTY 1682 Novato Blvd., Suite 150-A Novato, 94947 PHONE: (415) 499-6700 FAX: (415) 499-7543 MONTEREY COUNTY 1428 Abbott Street Salinas, 93901 PHONE: (831) 759-7325 FAX: (831) 422-5003 NAPA COUNTY 7292 Silverado Trail Yountville, 94599 PHONE: (707) 944-8714 FAX: (707) 944-0984 SACRAMENTO COUNTY 4137 Branch Center Road Sacramento, CA 95827 PHONE: (916) 875-6603 FAX: (916) 875-6150 SAN FRANCISCO COUNTY San Francisco Department of Public Health 1390 Market St., Suite 210 San Francisco, CA 94102 PHONE: (415) 252-3884 (Weights & Measures) FAX: (415) 252-3869 SAN JOAQUIN COUNTY 1868 East Hazelton Avenue Stockton, CA 95202 PHONE: (209) 468-3300 FAX: (209) 468-3330

SAN MATEO COUNTY Agriculture Building 728 Heller Street Redwood City, CA 94064 PHONE: (650) 363-4700 FAX: (650) 367-0130 SANTA CLARA COUNTY San Jose Office 1553 Berger Drive, Bldg. #1 San Jose, CA 95112 PHONE: (408) 918-4600 FAX: (408) 286-2460 SANTA CRUZ COUNTY 175 Westridge Drive (HQ) Watsonville, CA 95076 PHONE: (831) 763-8080 FAX: (831) 763-8255 SOLANO COUNTY 501 Texas Street Fairfield, CA 94533 PHONE: (707) 784-1310 FAX: (707) 784-1330 SONOMA COUNTY 133 Aviation Boulevard, Suite 110 Santa Rosa, 95403-2810 PHONE: (707) 565-2371 FAX: (707) 565-3850

Attachment E – PG&E/BOMA Survey Questions

For PG&E’s next Phase 2 GRC, PG&E and BOMA should conduct a statistically significant survey regarding commercial building master metering experience to date, in order to answer the following questions:

1) How many commercial buildings managed by BOMA members in PG&E’s service territory provide submetering options to its tenants? What percent of commercial buildings managed by BOMA members in PG&E’s service territory does this represent?

2) What is the approximate total building demand associated with commercial buildings managed by BOMA members in PG&E’s service territory that provide submetering options to their tenants?

3) Were there any noticeable changes to total building usage and usage patterns after the implementation of commercial submetering? Can those changes be quantified? If so, what are the results?

4) What were the actual monthly meter, meter reading and billing charges for submetered service that were billed to submetered customers?

5) How were the monthly meter, meter reading and billing charges determined and calculated?

6) Were the monthly meter, meter reading and billing charges determined and calculated consistently by building owners?

7) How do the building owner charges for the monthly meter, meter reading and billing compare to what PG&E would charge for the same activities?

8) How do submetered tenants’ total bills (metered plus common allocation) compare to what would have been charged under the previous square footage allocation for the entire bill?

9) For submetered tenant charges, including those related to metered energy use, allocated demand charges and landlord determined charges for meters, meter reading and billing, how do commercial tenant bills compare to what PG&E would have charged a customer for direct service on an appropriate comparable tariff schedule?

10) What types of guidelines and help, if any, were provided to building owners by BOMA or PG&E regarding meter installation, meter O&M, meter reading, and billing?

11) What types of problems were experienced by building owners with regard to meter installation, meter O&M, meter reading, and calculating bills? How were those problems reconciled?

12) To what extent did building owners provide appropriate information to their submetered tenants relating to available dynamic pricing options and energy efficiency programs, including those programs requiring landlord assistance in order to participate?

13) To what extent did commercial tenants participate in dynamic pricing and energy efficiency programs, including those programs requiring landlord assistance in order to participate?

14) How can commercial building master metering be improved?

Attachment F – CPUC Decision D.07-09-004 ALJ/DKF/hkr/sid Date of Issuance 9/7/2007 Decision 07-09-004 September 6, 2007

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

Application of Pacific Gas and Electric Company To Revise Its Electric Marginal Costs, Revenue Allocation, and Rate Design.

(U 39 M)

Application 06-03-005 (Filed March 2, 2006)

INTERIM OPINION ADOPTING SETTLEMENTS ON MARGINAL COST, REVENUE ALLOCATION,

AND RATE DESIGN

A.06-03-005 ALJ/DKF/hkr/sid

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TABLE OF CONTENTS

Title Page INTERIM OPINION ADOPTING SETTLEMENTS ON MARGINAL COST, REVENUE ALLOCATION, AND RATE DESIGN..................................................... 2

1. Summary................................................................................................................... 2 2. Background............................................................................................................... 3 3. Settlements................................................................................................................ 5

3.1. Marginal Cost and Revenue Allocation Settlement................................... 6 3.2. Residential Rate Design ................................................................................. 7 3.3. Streetlight Rate Design................................................................................... 9 3.4. Medium and Large Light & Power Rate Design...................................... 10 3.5. Small Light & Power Rate Design .............................................................. 11 3.6. Agricultural Rate Design ............................................................................. 13 3.7. Commercial Building Master Meter Issues............................................... 13

4. Standard of Review ............................................................................................... 14 4.1. All-Party Settlements.................................................................................... 15 4.2. Contested Settlements .................................................................................. 16

5. Uncontested Settlement Agreements ................................................................. 16 5.1. All-Party Settlements.................................................................................... 16 5.2. Reasonableness in Light of the Record ...................................................... 17 5.3. Consistency with Law .................................................................................. 21 5.4. The Public Interest ........................................................................................ 22 5.5. Annual Reports to Provide Information on Marginal Costs Are Unnecessary ........................................................................................... 22

6. Master Meter Settlement Agreement.................................................................. 24 6.1. TURN Contests the Master Meter Settlement .......................................... 26 6.2. Reasonableness in Light of the Record ...................................................... 26

6.2.1. Position of TURN............................................................................... 26 6.2.2. Position of BOMA.............................................................................. 29 6.2.3. Discussion........................................................................................... 33

6.3. Alternative Terms and Conditions............................................................. 38 6.3.1. Common Loads Should not Be Allocated to Tenants .................. 38 6.3.2. Submeters Should Provide at Least the Same Information as the Master Meter ........................................................................... 39 6.3.3. Tenants Should Be Provided With the Same Information Currently Provided to Residential Submetered Tenants by the Utility and the Master Meter Customer Pursuant to D.04-11-033 and D.05-05-026 ....................................................... 39


6.3.4. PG&E Should Allow Submetering Only Where the Master Meter Customer Meets Certain Requirements.............................. 43

6.4. Consistency with Law .................................................................................. 44 6.4.1. D.63562 ................................................................................................ 46 6.4.2. D.92109 ................................................................................................ 47 6.4.3. D.99-10-065 ......................................................................................... 50 6.4.4. D.05-05-026 ......................................................................................... 52

6.5. The Public Interest ........................................................................................ 54 6.5.1. Discussion........................................................................................... 54

6.6. Conclusion on Master Meter Settlement ................................................... 54 7. Comments on Proposed Decision ....................................................................... 55 8. Assignment of Proceeding ................................................................................... 56

Findings of Fact............................................................................................................... 56 Conclusions of Law ........................................................................................................ 60 INTERIM ORDER........................................................................................................... 61 APPENDICES: Appendix A—List of Appearances Appendix B—Settlement Agreement on Marginal Cost and Revenue Allocation Issues Appendix C—Supplemental Settlement Agreement on Residential Rate Design Issues Appendix D—Supplemental Settlement Agreement on Streetlight Rate Design Issues Appendix E—Supplemental Settlement Agreement on Medium and Large Light and Power Rate

Design Issues Appendix F—Supplemental Settlement Agreement on Agricultural Rate Design Issues Appendix G—Supplemental Settlement Agreement on Small Light and Power Rate Design

Issues Appendix H—Supplemental Settlement Agreement on Commercial Building Master Meter

Issues

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INTERIM OPINION ADOPTING SETTLEMENTS ON MARGINAL COST, REVENUE ALLOCATION,

AND RATE DESIGN 1. Summary

This decision concerning Phase 2 of Pacific Gas and Electric Company�’s

(PG&E) general rate case (GRC) adopts electric marginal costs and principles for

revenue allocation to the customer class level and the design of tariff schedule

rates. Revised rates will become effective November 1, 2007 and will allow

PG&E to collect the revenue requirement determined in Phase 1 of its 2007 GRC,

as modified by subsequent revenue requirement authorizations.

PG&E and interested parties have submitted a range of evidence, engaged

in settlement discussions, and filed motions for Commission adoption of a

settlement agreement regarding marginal cost and revenue allocation, plus five

supplemental rate design settlement agreements and a supplemental settlement

agreement on commercial building master meter issues. We find that the

marginal cost and revenue allocation and five supplemental rate design

settlement agreements meet our tests for adoption, and grant the motions to

adopt those settlements. We also adopt the commercial building master meter

settlement agreement with the condition that PG&E and building owners

provide tenants with information concerning rates and their consumer rights and

that PG&E and the Building Owners and Managers Associations provide certain

information on their experience with commercial building master metering in

PG&E�’s next GRC.

The proceeding remains open to consider future dynamic pricing tariffs

and options for PG&E.


2. Background Consistent with the Commission�’s Rate Case Plan (RCP), PG&E�’s GRC is

considered in two phases�—Phase 1 to consider revenue requirement issues and

Phase 2 to consider marginal cost, revenue allocation, and rate design issues.

PG&E filed its 2007 GRC Phase 1 Application (A.) 05-12-002 on December 2,

2005. Pursuant to the RCP, PG&E�’s Phase 2 proposal is due 90 days after its

Phase 1 filing. Thus, PG&E�’s Phase 2 proposal was filed on March 2, 2006 by

A.06-03-005.1 In support of its request, PG&E provided testimony on its

marginal cost, revenue allocation, and rate design proposals.

Ten public participation hearings (PPHs) were held at various locations in

PG&E�’s service territory during April and May 2006.2 Letters, electronic mail

messages and petitions representing the views of hundreds of ratepayers were

also received at the Commission.

A PHC for Phase 2 was held on May 3, 2006. On May 25, 2006, the

Assigned Commissioner�’s Ruling and Scoping Memo was issued. The Scoping

Memo, among other things, determined that the category for this proceeding is

ratesetting, stated the issues, and set the schedule.

1 On January 23, 2006, the Commission held a prehearing conference (PHC) in PG&E�’s Phase 1 application. At the PHC, PG&E indicated that it planned to submit its Phase 2 proposal in the same docket as its Phase 1 showing, consistent with the RCP. Assigned Commissioner Bohn issued a ruling on February 3, 2006, directing PG&E to �“file a separate application for Phase 2 issues�” on the grounds that such �“treatment of Phase 2 issues is consistent with recent GRC proceedings and the Commission�’s responsibility under Pub. Util. Code § 1701.5 to complete ratesetting proceedings within 18 months.�” Consistent with the ruling, PG&E submitted its test year 2007 Phase 2 showing as a separate application.

2 The PPHs addressed both the Phase 1 and Phase 2 applications and were held at the following locations: Oakland, Ukiah, Santa Rosa, King City, Salinas, San Louis Obispo, Modesto, Fresno, Woodland, and Chico.

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Consistent with the Scoping Memo schedule, PG&E served update

testimony on June 26, 2006, Division of Ratepayer Advocates (DRA) served its

testimony on September 13, 2006, and other parties served their testimonies on

October 27, 2006.3 A meet and confer session on settlement issues was held on

September 20, 2006. A mandatory settlement conference was then held on

November 1, 2006. On November 6, 2006, PG&E, on behalf of the Settling

Parties, contacted the assigned administrative law judge (ALJ) and requested an

extension of the schedule to accommodate further settlement discussions. That

request was granted by ALJ Ruling of November 9, 2006. Subsequent requests

for extensions of time to accommodate the settlement process were granted by

ALJ Rulings of December 14, 2006, January 9, 2007, March 22, 2007, and April 24,

2007. Evidentiary hearing was held April 17, 2007. The marginal cost, revenue

allocation, and rate design phase of this application was submitted for decision

on May 25, 2007.

3 Concurrently, on a separate track, the Commission was considering PG&E�’s request for an expedited decision on the agricultural definition issue. A settlement between PG&E and all parties concerned with this issue was ultimately adopted by Decision (D.) 06-11-030.

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3. Settlements On behalf of the Settling Parties,4 PG&E filed four motions for adoption of

settlement agreements. The first motion, filed on February 9, 2007, was for

marginal cost and revenue allocation. The second motion, filed on March 16,

2007, was for residential rate design, streetlight rate design, and medium and

large light and power rate design. The third motion, filed on April 27, 2007, was

for small light and power rate design, and commercial building master metering.

The fourth motion, filed on May 4, 2007, was for agricultural rate design. The

five rate design settlement agreements and the commercial building master

meter settlement agreement are supplemental to the marginal cost and revenue

allocation settlement agreement filed on February 9, 2007. The rate design

settlement agreements use the revenue allocation agreed to in the February 9

settlement and address rate design issues that were not resolved in that

settlement.

The entirety of PG&E�’s request in this proceeding is resolved by the

marginal cost and revenue allocation settlement agreement, the five

4 The Settling Parties are the following: Agricultural Energy Consumers Association (AECA); Building Owners and Managers Associations of San Francisco, Greater Los Angeles, Orange County, and California (BOMA); California City-County Street Light Association (CAL-SLA); California Farm Bureau Federation (CFBF); California Large Energy Consumers Association (CLECA); California League of Food Processors (CLFP); California Manufacturers & Technology Association (CMTA); California Retailers Association (CRA); California Rice Millers (CRM); California Solar Energy Industries Association (CAL SEIA); Cogeneration Association of California (CAC); Direct Access Customer Coalition (DACC); DRA; Energy Producers and Users Coalition (EPUC); Energy Users Forum (EUF); Federal Executive Agencies (FEA); Indicated Commercial Parties (ICP); PG&E; PV Now; The Utility Reform Network (TURN); Vote Solar; and The Western Manufactured Housing Communities Association (WMA). All parties signed the marginal cost and revenue allocation settlement agreement. Each party signed only those supplemental settlement agreements that pertained to their specific interests.

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A.06-03-005 ALJ/DKF/hkr/sid supplemental rate design settlement agreements and the supplemental

commercial building master meter settlement agreement. The commercial

building master meter settlement agreement is contested by TURN. All other

settlement agreements are uncontested.

3.1. Marginal Cost and Revenue Allocation Settlement

The marginal cost and revenue allocation (MCRA) settlement agreement

addresses three major issues. First, the Settling Parties agree that the primary

purpose of determining marginal costs in this proceeding is to establish the cost

of providing service by rate group for the generation and distribution functions.

Since marginal costs were last adopted for revenue allocation and rate design

purposes in 1993, the Settling Parties agree that this proceeding should result in

updated marginal costs. While the Settling Parties disagree on the specific

principles that should be employed to calculate marginal costs, the Settling

Parties generally agree on the marginal cost values to be employed for the

defined purposes described in this settlement agreement.

Second, the Settling Parties agree that electric revenue should be allocated

on an overall revenue-neutral basis. This settlement agreement begins with the

principle that generation and distribution revenue should be adjusted 85% of the

way from then-current distribution and generation revenue to revenue at equal

percent of marginal cost (EPMC), as defined in the settlement agreement. This

settlement agreement includes additional key allocation principles and, as a final

step, the Settling Parties agree that the annual average bundled rates will be

limited by adjusting the generation allocation such that total bundled rates

change as provided below, with any resulting shortfall to be collected from all

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A.06-03-005 ALJ/DKF/hkr/sid other customer groups except Standby based on an equal percent of generation

revenue.

Residential Class: 2.8%

A-10 Class: -5.0%

E-19 Secondary (firm and non-firm combined): -9.0%

Agricultural Class: 4.0%

Streetlighting Class: -9.0%

E-20 Transmission Firm: 0.0%

E-20 Primary Firm: -2.0%

E-20 Secondary Firm: -9.0%

Third, this settlement agreement addresses rate changes between GRCs.

The Settling Parties agree that each customer group will be held responsible for

approximately the same percentage contribution to each component of rates.

This will be accomplished by implementing changes to the revenue requirement

for each component by applying to each rate schedule the same percentage

change to rates by component required to collect the revenue requirement for

that component, with specific exceptions to this treatment set forth in the

settlement agreement.

3.2. Residential Rate Design The residential rate design settlement agreement describes the manner in

which residential rates will be designed and includes the following fundamental

components:

Total bundled residential California Alternate Rates for Energy (CARE) rates will remain unchanged subject to the provisions of the February 9 settlement.

Residential baseline quantities will be revised in accordance with PG&E�’s testimony, subject to the Assembly Bill (AB) 1X

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restrictions on residential customers for usage up to 130% of baseline. Baseline quantities and revenue-neutral rate adjustments will be phased in beginning on May 1, 2008 for electric customers and April 1, 2008, for gas customers, subject to certain caveats.

Total bundled rates for usage up to 130% of baseline will not be changed so long as AB 1X�’s rate restrictions are effective, subject to certain caveats. While such restrictions are effective, revenue increases to the residential class will be implemented as proportional changes to the generation surcharges in Tiers 3, 4, and 5, and revenue reductions to the residential class will be implemented by proportionally reducing generation surcharges in Tiers 3, 4, and 5.

If a reduction to the residential class in excess of 3% is expected, PG&E will consult with DRA and TURN to determine the proper method of allocating that revenue between tiers, but rates for usage up to 130% of baseline will not be reduced.

Distribution and generation rates for non-CARE residential rate schedules will be differentiated by tier, and distribution and generation revenue on non-CARE rate schedules will be collected in each tier in the same proportion as the generation and distribution revenue is allocated to each rate schedule, prior to determining rates for the California Solar Initiative (CSI).

The CSI rate will be determined as an equal proportion of pre-CSI distribution revenue in each tier as required to collect the CSI revenue allocated to the non- CARE residential schedules. Special provisions apply to customers taking service on the Family Electric Rate Assistance (FERA) program.

The master-meter discount for Schedules ET and ES agreed to in PG&E�’s 2003 GRC Phase 2 proceeding will remain in place until a new electric master meter discount is adopted in another PG&E rate design proceeding.5

5 By letter of June 27, 2007 to the Executive Director of the Commission, PG&E, on behalf of itself, TURN, WMA and DRA requested that the deadline for completing a new diversity benefit study, which will be used to determine a new electric master meter discount, be extended from July 1, 2007, to August 1, 2007. That request was

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The residential settlement also includes provisions regarding the

minimum average rate limiter for residential master-metered customers that

receive a submeter discount; CARE customers taking direct access (DA) and

community choice aggregation (CCA) service; ongoing time-of-use (TOU) meter

charges for voluntary residential rate schedules; franchise fee surcharge

calculation for DA and CCA service; time-variant tariffs for solar customers;

time-of-use schedule for multifamily accounts currently eligible to take service

under Schedules EM or EML; customers on submetered rate schedules and

eligibility for CSI incentives; revisions to Schedule E-9 for electric vehicles; and

timing of rate changes.

3.3. Streetlight Rate Design The streetlight rate design settlement agreement describes the manner in

which rates for streetlight customers will be designed and includes the following

fundamental components:

Non-energy streetlight rates are set forth in Exhibits A and B to the settlement.

A specific formula will be used to calculate the energy charge for streetlights.

There will be an upper-most limit of 150 watts of non-conforming load on customer-owned streetlight circuits.

The streetlight settlement also includes provisions regarding

Schedule TC-1 (traffic control service) and additional streetlight rate design

matters as set forth in PG&E�’s direct testimony. The streetlight settlement

reasonable, and since the study was filed by August 1, 2007, we consider the parties to be in compliance with the filing date requirements for the study.

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A.06-03-005 ALJ/DKF/hkr/sid includes attachments with draft tariffs required to implement the settlement�’s

terms.

3.4. Medium and Large Light & Power Rate Design

The medium and large light & power (MLLP) rate design settlement

agreement describes the manner in which rates for the customer class will be

designed and includes the following fundamental components:

The basic rate designs for each of the applicable MLLP rate schedules will be updated upon settlement implementation using the methods underlying development of the illustrative settlement rates for Schedules A-10, A-10 TOU, E-19, E-20, and Standby presented in Exhibit A to the settlement.

There will be one additional modification of PG&E�’s MLLP proposals to ensure that total bundled service volumetric rates by TOU period under Schedules E-19 and E-20 will vary at least in proportion to the variation in PG&E�’s marginal energy costs. That is, for service at transmission and primary distribution service voltages, Schedule E-19 and E-20 TOU generation energy charges will be set residually so that the sum of generation energy charges and those non-bypassable charges that do not vary by TOU period vary in direct proportion to the TOU profile established by the settlement generation energy marginal costs.

PG&E�’s proposed customer charges for the MLLP rate schedules are reasonable, and the ongoing monthly TOU meter charges currently applicable for customers taking voluntary TOU service under Schedules E-19V and A-10 TOU should no longer be applied when the customer�’s existing TOU meter is replaced as part of the Advanced Meter Infrastructure (AMI) Project and the new meter is activated and used for billing.

Rate Limiters for Schedules E-19 and E-20 will be modified so that summer season average rate limiters will continue for Schedule E-19 and E-20 customers taking service at secondary and primary distribution voltages (at revised levels set forth in Exhibit A to the settlement).

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The MLLP settlement also includes provisions regarding standby service

rates, non-firm customers transferring to base interruptible program

Schedule E-BIP and enrolling on Schedule E-DBP (PG&E�’s demand bidding

program), franchise fee surcharge calculation for DA and CCA customers, and

timing of rate changes.

3.5. Small Light & Power Rate Design The small light & power (SLP) rate design settlement describes the manner

in which rates for that customer class will be designed and includes the

following fundamental components:

Revenue neutrality will be established between Schedules A-1 and A-6 in two steps. In the first step, upon settlement implementation, Schedules A-6 and A-1 will move approximately two-thirds of the way toward full revenue neutrality. The movement toward full revenue neutrality will occur on January 1, 2010, and will be maintained until the next GRC Phase 2 proceeding. These adjustments will correct current inappropriate rate relationships whereby customers can realize significant bill savings simply by switching from Schedule A-1 to A-6 despite having poor TOU load profiles.

The basic rate designs for each of the applicable SLP rate schedules will be updated upon settlement implementation using the methods underlying development of the illustrative settlement rates for Schedules A-1, A-6, A-15, and TC-1 presented in Exhibit B to the settlement.

The maximum demand limit for up to a cumulative total of 20 megawatts of solar system capacity among participating Schedule A-6 customers who install a solar photovoltaic system will increase from 500 kilowatts to 1,000 kilowatts. This increase will allow a customer whose maximum billing demand has been between 499 and 999 kilowatts for at least three consecutive months during the most recent 12-month period, or who otherwise is currently taking service, or would be required to take service, on Schedule E-19 on a mandatory basis to

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voluntarily move to Schedule A-6, so long as the customer installs a solar photovoltaic system that meets at least 20% of the measured maximum demand. Current mandatory Schedule E-19 solar customers who meet these criteria will have a one-time option to switch to Schedule A-6 within 90 days of settlement implementation, and will count toward the 20 megawatt pilot program cap.

The ongoing monthly TOU meter charges currently applicable for customers taking voluntary TOU service under SLP schedules will cease once the customer�’s existing TOU meter is replaced as part of the AMI Project and the new meter is activated and used for billing.

The calculation of the CARE discount for commercial CARE customers under Schedule E-CARE shall be based on a rate per kWh discount, rather than the current methodology, which is tied to percentage discount, surcharges, and June 10, 1996 rates. The new methodology will improve customer understanding of the rate, simplify billing, avoid the current requirement to calculate a phantom bundled bill for DA commercial CARE customers, and maintain parity between residential and commercial CARE average discount percentages.

Revised SLP TOU tariffs are deemed to fulfill the requirements of Senate Bill (SB) 1, Public Utilities Code Section 2851(a)(4), in terms of creating the maximum incentive for ratepayers to install solar systems, but settling parties are not restricted from taking positions they deem appropriate in a subsequent proceeding that addresses time-variant rates. However, prior to the next GRC Phase 2 proceeding, no settling party may argue that the SLP TOU rates do not meet the SB 1 requirement.

The SLP settlement also includes provisions regarding the SLP fixed

monthly customer charge, the special facility charge related to direct current

electrical service on Schedule A-15, and the franchise fee surcharge calculation

applicable to DA and CCA service.

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3.6. Agricultural Rate Design The agricultural settlement describes the manner in which agricultural

rates will be designed and includes the following fundamental components:

The basic rate designs for each of the applicable agricultural rate schedules will be updated upon settlement implementation using the methods underlying development of the illustrative settlement rates for Schedules AG-1, AG-R, AGV, AG-4, AG-5, and E-37 presented in Exhibit B to the settlement. These methods include a general widening of TOU energy charge differentials and mitigation of summer maximum demand charges where necessary.

Customer charges for Schedules AG-A, AG-B, AG-C, AG-5B, AG-5C, and AG-4C will be increased as shown in Exhibit B to the settlement.

The ongoing monthly TOU meter charges currently applicable to voluntary AG TOU rate schedules will no longer be applied as each customer�’s AMI meter is installed and used for billing.

The agricultural settlement also includes a provision regarding the

franchise fee surcharge calculation applicable to DA and CCA service.

3.7. Commercial Building Master Meter Issues The commercial building master meter (MM) settlement agreement

describes principles to govern the manner in which commercial building owners

may allocate costs to their commercial tenants so that those tenants may receive

price signals through the allocation of non-common master meter energy costs.

The MM settlement includes the following fundamental components:

The settling parties (PG&E and BOMA) agree that it is in the public interest that commercial building tenants receive price signals and have the opportunity to participate in dynamic pricing and energy conservation programs.

PG&E and BOMA agree that it is in the public interest that building owners participate in dynamic pricing and energy

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conservation programs, and BOMA agrees to encourage its membership to do so, and to timely pass on to commercial tenants dynamic pricing and energy conservation options or incentives that may become available. Revisions to PG&E Electric Rules 1 and 18 designed to accomplish the goals of the MM settlement are attached to the MM settlement.

Nothing in this MM settlement is intended to create or constitute evidence of a wholesale relationship between PG&E and commercial building owners, a commercial relationship between PG&E and tenants in commercial buildings, or a utility relationship between commercial building owners and their tenants.

PG&E and BOMA agree that the cost of electricity allocated to commercial building tenants will, in total, be equal to the charges billed by PG&E to the building owners under the Commission approved rate schedule servicing the master meter.

PG&E and BOMA agree that all attachments and devices on the customer's side of the master meter used to measure tenant electricity use for the purpose of taking advantage of dynamic pricing and energy conservation opportunities shall conform to all applicable safety rules, regulations, and general orders established by state and local governments.

The MM settlement also includes provisions further defining the

applicability and limitations of the new rules, regarding participation in

Commission proceedings addressing how dynamic pricing and energy

conservation programs may be made available to commercial building tenants,

and providing for the payment of the costs associated with implementation of

the terms of this agreement.

4. Standard of Review In reviewing settlements, we have often acknowledged California�’s strong

public policy favoring settlements. This policy supports many worthwhile goals,

such as reducing litigation expenses, conserving scarce resources of parties and

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the Commission, and allowing parties to reduce the risk that litigation will

produce unacceptable results.

In assessing settlements we consider individual settlement provisions but,

in light of strong public policy favoring settlements, we do not base our

conclusion on whether any single provision is the optimal result. Rather, we

determine whether the settlement as a whole produces a just and reasonable

outcome.

We have specific rules regarding approval of settlements:

�“The Commission will not approve settlements whether contested or uncontested, unless settlement is reasonable in light of the whole record, consistent with law, and in the public interest.�” (Rule 12.1(d).)

4.1. All-Party Settlements As first articulated in 1992, we condition our approval of an all-party

settlement on the following factors:

a. The settlement agreement commands the unanimous sponsorship of all active parties;

b. Sponsoring parties are fairly reflective of the affected interests;

c. No settlement term contravenes statutory provisions or prior Commission decisions; and

d. The settlement conveys sufficient information to permit the Commission to discharge future regulatory obligations with respect to parties and their interests.6

Settling Parties assert that the MCRA Settlement and the five rate design

settlements each meet the all-party tests. Further, they contend that each of these

6 D.92-12-019 (64 CPUC 2d 538, 550-551).

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settlements meet the broader tests of being reasonable in light of the whole

record, consistent with law, and in the public interest.

4.2. Contested Settlements We recently affirmed our long-standing policy �“that contested settlements

should be subject to more scrutiny compared to an all-party settlement.�”7 We

explained the rationale behind this heightened scrutiny in D.07-03-044:

In judging the reasonableness of a proposed settlement, we have sometimes inclined to find reasonable a settlement that has the unanimous support of all active parties in the proceeding. In contrast, a contested settlement is not entitled to any greater weight or deference merely by virtue of its label as a settlement; it is merely the joint position of the sponsoring parties, and its reasonableness must be thoroughly demonstrated by the record. (D.07-03-044, p. 13 (quoting D.02-01-041, p. 13).)

Accordingly, we undertook a careful review of every issue raised by the

parties contesting the settlement at issue in D.07-03-044.

The MM settlement is not an all-party settlement. It is contested and

opposed by TURN. Therefore, in considering whether it warrants adoption we

must review it as the joint position of PG&E and BOMA, who have the burden to

thoroughly demonstrate its reasonableness. This is accomplished further in the

decision where we address TURN�’s objections to the MM settlement and

BOMA�’s and PG&E�’s responses to those objections.

5. Uncontested Settlement Agreements

5.1. All-Party Settlements We agree with the Settling Parties�’ assertions that the MCRA settlement

and five rate design settlements are all party settlements. Each settlement was

7 D.07-03-044, Opinion Authorizing PG&E�’s GRC Revenue Requirement for 2007-2010, mimeo., p. 13 (citing D.96-01-011, Finding of Fact 5).

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signed and endorsed by each and all of the parties that provided testimony on

that particular settlement�’s subject matter.8 While participation in each of the

settlements varied depending on parties�’ specific interests, a review of the

signatories to each of the settlements indicates that the sponsoring parties are

fairly reflective of the affected interests. Also, as discussed below, the

settlements are consistent with law. Finally, based on the record that contains

the testimonies of all parties and the settlement provisions regarding the timing

of rate changes and the manner of implementing rate changes between GRCs, we

determine that the settlements convey sufficient information to permit the

Commission to discharge future regulatory obligations.

5.2. Reasonableness in Light of the Record The MCRA settlement is an uncontested all-party settlement. In total there

were 22 parties participating in negotiations related to the MCRA settlement,

with representation for all affected rate classes. While there were a number of

differences in the marginal costs and revenue allocations proposed by the

various parties in prepared testimonies, settlement appears to provide a

reasonable compromise of parties�’ positions in developing marginal costs and

calculating revenue allocation for this proceeding. The settlement does not adopt

any of the Settling Parties�’ marginal cost principles or proposals, but the Settling

Parties do agree that it is reasonable for the Commission to approve the marginal

8 Merced Irrigation District (Merced ID) and Modesto Irrigation District (Modesto ID) filed comments on the MCRA settlement, requesting certain marginal cost reporting requirements for PG&E to provide information that may be of use in future proceedings. The manner in which information should be reported for future proceedings is not addressed by the MCRA settlement. Also, neither Merced ID nor Modesto ID filed testimony in this proceeding, and they indicate they do not oppose the MCRA settlement. For these reasons, we consider the MCRA settlement to be an all-party settlement, even though Merced ID and Modesto ID were not sponsors.

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costs in the settlement for the purposes of establishing unit costs in the

development of revenue allocation and rate design in this proceeding and for

customer-specific contract rate floors for customer retention and attraction.

By the EPMC revenue allocation, the revenue requirement is allocated

proportionately to the various rate classes based on the marginal costs, or a

certain percentage of the marginal costs, of each class. The Commission�’s general

policy goal is full or 100% EPMC revenue allocation for all rate classes.9

Consistent with this policy, the settlement moves the allocation of revenues to

the various customer classes to more closely reflect full marginal costs on an

EPMC basis. The following table shows the present revenue allocation and the

settlement proposed revenue allocation, each with the associated percentages of

EPMC.

9 See D.82-12-113 (10 CPUC 2d 512), D.83-12-065 (13 CPUC 2d 619), D.83-12-068 (14 CPUC 2d 15), and D.84-12-068 (16 CPUC 2d 721).

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REVENUE ALLOCATION SUMMARY (Revenue in Thousands of Dollars)

Full EPMC Present % of Settlement % of

Bundled Revenue Revenue Full EPMC Revenue Full EPMC

Residential $4,846,274 $4,667,646 96.31% $4,798,987 99.02%Small L&P 1,395,156 1,328,011 95.19% 1,402,254 100.51%

Medium L&P 1,635,253 1,784,596 109.13% 1,695,207 103.67%Schedule E-19 1,084,588 1,218,790 112.37% 1,115,054 102.81%

Streetlights 62,066 69,413 111.84% 63,166 101.77%Standby 30,693 29,823 97.16% 30,689 99.99%

Agriculture 632,012 565,022 89.40% 587,570 92.97%Schedule E-20 1,064,023 1,103,240 103.69% 1,060,222 99.64%

Total Bundled $10,750,066 $10,766,541 100.15% $10,753,149 100.03%

Direct Access

Residential $4,029 $4,102 101.81% $4,021 99.82%Small L&P 6,835 5,887 86.13% 6,807 99.59%

Medium L&P 71,928 67,124 93.32% 71,847 99.89%Schedule E-19 66,223 69,221 104.53% 67,432 101.83%

Agriculture 2,693 2,960 109.90% 2,794 103.75%Schedule E-20 117,423 104,726 89.19% 113,781 96.90%

FPP 4,403 3,086 70.08% 3,791 86.08%

Total Direct Access $273,533 $257,106 93.99% $270,473 98.88%

Total Bundled & DA $11,023,599 $11,023,647 100.00% $11,023,622 100.00%

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As can be seen from the table, the MCRA settlement proposal makes

significant progress towards 100% EPMC revenue allocation for all rate classes.

We find the settlement revenue allocation proposal to be reasonable.

The rate design settlements for each of the customer classes provide

principles for developing the various rate tariffs from which customer bills will

be calculated. Illustrative rates based on the revenue allocations included in the

MCRA Settlement are provided. While rate design is an extremely complex

process, compared to the number of marginal cost and revenue allocation issues

identified in and addressed in the MCRA settlement, the number of identified

rate design issues was small.

The residential, streetlight, SLP, MLLP and agricultural rate design

settlements are all-party settlements. Each settlement included participation and

agreement from each of the parties that prepared testimony related to the

particular customer class being addressed.10 There is no opposition to any of

these five rate design settlements. We note that all parties had the opportunity to

review the results of other settlements for impacts on their interests, and no party

objects to any of the settlements being discussed here.

10 CAL SEIA, DRA, PG&E, PV Now, TURN, Vote Solar, and WMA are signatories to the residential rate design settlement.

CAL-SLA and PG&E are signatories to the streetlight rate design settlement.

CAL-SLA, CAL SEIA, DRA, PG&E, PV Now, TURN, and Vote Solar are signatories to the small light & power rate design settlement

BOMA, CLECA, CLFP, CMTA, CRA, CAC, DACC, EPUC, EUF, FEA, ICP, and PG&E, are signatories to the medium and large light & power rate design settlement.

AECA, CFBF, CRM, CAC, EPUC and PG&E are signatories to the agricultural rate design settlement.

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Based on the evidentiary record of this proceeding, principally prepared

testimonies, and the all-party status of the settlements, we find that each of the

five rate design settlements fairly resolves identified issues and is reasonable.

5.3. Consistency with Law We agree with the Settling Parties�’ assertion that the MCRA settlement

agreement and each of the five rate design agreements are consistent with law.

The process for conducting these settlements was in accordance with Article 12

of the Rules of Practice and Procedure. Further, there are no allegations, and we

do not detect, that any element of the MCRA or five rate design settlements is

inconsistent in any way with Public Utilities Code Sections, Commission

decisions, or the law in general.

We do note certain consistencies such as conformance to the AB 1X

residential rate restrictions; consistency with Section 2851(d)(2) which requires

CSI costs to be imposed on all customers not participating in the California

CARE or FERA programs, including those residential customers subject to the

rate cap for existing baseline quantities or usage up to 130% of existing baseline

quantities of electricity; the phase-in of full cost streetlight rates for the City and

County of San Francisco, consistent with prior Commission directives

(Resolution E-3203 and D.93-06-087); and the development of revised

Schedules E-6 and EL-6 to fulfill the requirements of Section 2851(a)(4), requiring

�“a time-variant tariff that creates the maximum incentive for ratepayers to install

solar systems�…�”11

11 Since the settlement agreements were filed with the Commission, the Legislature passed Assembly Bill 1714, amending SB 1 to allow the Commission to delay the requirement that CSI customers take time variant pricing �“until the effective date of the rates subject to the next general rate case of the state�’s three largest electrical corporations, scheduled to be completed after January 1, 2009.�” (See Pub. Util. Code

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5.4. The Public Interest We agree with the Settling Parties�’ assertion that the MCRA settlement

agreement and each of the five rate design agreements are in the public interest.

There are no allegations, and we do not detect, that any element of the MCRA or

five rate design settlements is inconsistent in any way with the public interest.

The settlements are reasonable compromises of Settling Parties�’ respective

litigation positions. The settlements avoid the cost of further litigation, and

conserve scarce resources of parties and the Commission. It was important to get

marginal costs revised in this proceeding because they had not been revised and

adopted by the Commission since 1993. The settled revenue allocation

moderates potentially harsh bill impacts while better aligning rates with costs.

Also as stated earlier, Schedules E-6 and EL-6 provide a time-variant tariff that

creates the incentives for ratepayers to install solar systems.

5.5. Annual Reports to Provide Information on Marginal Costs Are Unnecessary

Merced ID and Modesto ID (collectively, the Districts) filed comments on

the proposed MCRA settlement. Merced ID and Modesto ID are both customers

of PG&E and competitors in the provision of electric services to customers in

California�’s central valley, and as such have an interest in the matters addressed

§ 2851(a)(4)(B).) In Decision 07-06-014, Opinion Modifying Decision 06-12-033 Regarding Time Variant Pricing Requirements (at p. 10), the Commission adopted such a delay. Accordingly, while the Settling Parties endorsed the schedules set forth in the Residential and Small Light and Power Agreements as being compliant with the time-variant requirement of Public Utilities Code Section 2851(a)(4), PG&E acknowledges that customers will not be required to take service on these time-variant rate schedules in order to receive CSI incentives until the first general rate case with rates effective after January 1, 2009. All the Settling Parties endorse and support PG&E�’s acknowledgement.

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A.06-03-005 ALJ/DKF/hkr/sid in the Settlement Agreement. While the Districts do not oppose the Settlement

Agreement, they indicate they were not able to participate as settling parties

because of competitive concerns regarding PG&E�’s calculation of distribution

marginal costs.

PG&E�’s location-specific distribution marginal cost approach was first

litigated and adopted in Phase 2 of PG&E�’s 1993 GRC and has remained in place

to date. In this proceeding, PG&E continues to use location-specific marginal

costs. The Districts understand that PG&E�’s marginal distribution capacity cost

approach in this proceeding is consistent with past practice and have not raised

this as an issue in this proceeding. However, the Districts are concerned that this

approach is outmoded and does not accurately reflect PG&E�’s current approach

to evaluating and implementing new distribution projects within its overall

system.

The Districts recommend that PG&E be required to submit annual reports

describing in detail the location of distribution projects undertaken during the

year, the cost of each project and the portion(s) of its territory the project is

intended to serve. That information could then be used in an appropriate future

proceeding to determine whether it is appropriate to calculate distribution

marginal capacity costs on a system-wide, rather than division, basis.

According to PG&E, it already provides the data requested by the Districts

in its GRCs, it will provide the same information in its next GRC, and there is no

need for the Commission to impose an additional annual reporting requirement

on PG&E that will provide no tangible value. PG&E states that if the

Commission were interested in reconsidering location-specific versus system-

wide distribution marginal cost methodologies, the Commission has many years

of historic data to rely on. Also, if the Districts wish to raise this issue in future

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GRC Phase 2 or other proceedings, the Districts or Commission could also

request more updated information from the utilities at that time, instead of

requiring annual reports in between rate proceedings.

We agree with PG&E on the need to file annual reports on marginal costs.

For GRCs, in general, there may be a number of issues that rely on the analysis of

detailed historic data. To require annual reporting of such information for costs

or methodologies that might be at issue in future proceedings is not an efficient

procedure. PG&E has provided evidence that the necessary information

identified by the Districts is available in its workpapers, and the amount of

information is substantial.12 Going forward, PG&E should continue to maintain

the same detailed information describing the location of distribution projects

undertaken during the year, the cost of the each project and the portion(s) of its

territory the project is intended to serve. If needed in future proceedings that

might consider the issue of location-specific versus system-wide marginal cost

methodologies, this information will be available, if not in workpapers then

through data requests. This procedure is reasonable, and we will not require

PG&E to file annual reports.

6. Master Meter Settlement Agreement The MM settlement agreement was negotiated between, and proposed by,

PG&E and BOMA. BOMA is a statewide association whose members are

commercial real estate professionals that own and/or manage commercial office

buildings in their respective regions and across other regions. Statewide, BOMA

members own and/or manage in excess of 600 million square feet of office space.

12 Information contained in exhibits 23, 24, 25, and 26.

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A.06-03-005 ALJ/DKF/hkr/sid These buildings are occupied by approximately 50,000 California businesses that

employ about two million workers.

Most commercial office building tenants are not customers of the serving

energy utility nor directly metered by the serving energy utility. Accordingly,

BOMA members take the responsibility for purchasing energy and managing

energy costs on behalf of their tenants. Under the existing language of PG&E�’s

Rule 18, the cost of electricity to the building may only be recovered through

rent, regardless of the tenant�’s individual usage. The Rule expressly provides

that nothing replicating a separate energy charge that varies with tenant usage

appear on statements for lease payments.

The restrictions embraced in Rule 18 have lead to the emergence of tenant

leases that require tenants to annually pay a share of electricity costs in

proportion to the square footage that they occupy. According to BOMA,

The allocation system based on square footage yields inequitable and inefficient allocations of energy costs. Low energy-intensive tenants subsidize the energy use of high energy-intensive tenants, and none of the tenants have the information and price incentives to efficiently manage their energy usage. That being the case, the tenant controlled portion of high rise commercial building load (30% to 40%) is shielded from participating in any form of demand response, thus impeding the State�’s efforts toward achieving higher level of demand response. The Settlement seeks modification of Rule 18 to allow more equitable and efficient allocation of electricity cost among tenants and, in so doing, to enhance the potential for obtaining greater statewide demand response and a more efficient electric system. The proposal is concerned with building owner recovery of electricity costs (and no more) in a manner that is more beneficial to tenants and electricity consumers than Rule 18 currently allows.

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6.1. TURN Contests the Master Meter Settlement On May 22, 2007, TURN filed comments contesting the MM settlement.

TURN states the MM settlement asks the Commission to lift the ban on new

submetering in commercial buildings which has been in effect since 1962. TURN

argues that the Commission should find that PG&E and BOMA have failed to

carry their burden of demonstrating that the MM settlement is in the public

interest. TURN recommends that the Settlement be rejected. However, if the

Commission is inclined to adopt the MM settlement, TURN urges the

Commission to condition approval on PG&E�’s and BOMA�’s acceptance of certain

modifications as proposed by TURN.

6.2. Reasonableness in Light of the Record 6.2.1. Position of TURN

According to TURN, the Commission has little to work with in terms of a

record, noting that PG&E and BOMA arrived at a settlement agreement prior to

parties having an opportunity to prepare testimony in rebuttal to BOMA�’s

Testimony, or before BOMA�’s Testimony could be tested through cross-

examination.13 It is TURN�’s position that neither the MM settlement nor

BOMA�’s Testimony provides sufficient information for the Commission to

conclude that the MM settlement is reasonable in light of the record.

TURN asserts that the proposed change to Rule 18 that would allow

implementation of commercial building master metering is too vague to provide

the Commission with any sense of what building owners may or may not do. To

illustrate its assertion, TURN posed a number of questions which are detailed

later in this decision along with the responses by BOMA. TURN also explains its

13 In its comments, TURN did not request evidentiary hearing or the opportunity to prepare testimony on contested issues as provided in Rules 12.2 and 12.3.

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A.06-03-005 ALJ/DKF/hkr/sid position that the MM settlement provides no guidance regarding how the master

meter customer will allocate electricity costs between submetered and non-

submetered tenants in a partially submetered building and does not specify

whether the building owner will be permitted to allocate costs associated with

common load electricity to tenants, such as through a proportionate share

allocator based on submetered tenant usage.

TURN also argues the following:

The Commission should have the same concerns with meter accuracy and reliability, meter reading, billing and adjustments as the Commission did in D.63562, D.92109 and D.99-10-065.

Tenants will receive bills from building owners that may or may not provide clear and useful information, such as would allow a tenant to verify charges. Tenants who suspect something might be wrong will have no real recourse other than to go to the building owner, whose practices may be the source of dispute.

Submetered commercial tenants will pay more for utility services than any other class of end users because they will effectively pay twice for meter installation and O&M, meter reading and billing.

In stark contrast to commercial tenants and the general body of ratepayers, commercial building owners would clearly benefit from the MM settlement. Building owners could pass to tenants all of the electricity costs associated with the building each month, and collect additional, seemingly unlimited costs associated with owning and operating the submetering and billing systems. Likewise, the MM settlement places glaringly few restrictions on building owners, other than requiring that their costs be allocated to submetered tenants such that electricity is billed at the same rate charged by PG&E to the master meter. As a result, the electric metering and billing practices of commercial building owners would be remarkably divergent, unexamined, and unregulated, to the detriment of their tenants.

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d

ls

e. Thus,

ic price signals�” and capture significant demand response.

Allocating to tenants a �“proportional�” share of the common costs of loads within the building owner�’s control will not promote demand response or increased efficiency in those loads, but will instead eliminate the incentive that building owners currently have �“to retrofit buildings, to invest in high efficiency equipment and appliances, and to adopt cutting edge energy management practices.�” Unless such potential is fully captured, allowing building owners to allocate common load costs to tenants through submetering will create lost opportunities for efficiency and demand response in high rise buildings in PG&E�’s service territory.

Claims of benefits related to dynamic pricing as applied to tenants are speculative and are inconsistent with the California Statewide Pricing Pilot�’s findings about demand elasticity in small commercial plug load. The Statewide Pricing Pilot found only a small amount of price elasticity from small commercial customers who comprise the bulk of commercial tenancies in California. Those with loads greater than 20 kW reduced usage an average of 9.1% during critical days, whereas those with loads less than 20 kW had merely a 1.5% reduction.14 Moreover, the MM settlement would merely provide most tenants with TOU price signals, far less drastic than the CPP �“signals�” at issue in the State Pricing Pilot (and, presumably, far less likely to produce reduceusage).

Submetered tenants may not receive dynamic pricing signaat all under the MM settlement, since it does not require a building owner to take service on a �“dynamic pricing�” tariff, and currently some eligible high rise buildings take service on Rate Schedule A-10, which is not even a TOU schedulthe Commission should give little weight to the MM settlement�’s suggestion that it will provide commercial tenants with �“dynam

14 �“Impact Evaluation of the California Statewide Pricing Pilot,�” Charles River Associates, 3/16/05, R.02-06-001, p. 13.

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Some of PG&E�’s energy efficiency programs limit participation in the rebate/incentive component to the customer of record, meaning that submetered tenants could only participate with the assistance of the building owner. A submetered tenant desiring to take advantage of a PG&E rebate/incentive program and invest in high efficiency office appliances or equipment would still be dependent on the building owner�’s willingness and cooperation, even under the MM settlement. And in a submetered environment, the building owner would not have the same economic motivation to help tenants reduce their loads as they would under today�’s Rule 18. Furthermore, the energy efficiency programs PG&E administers do not provide rebates or incentives for measures generally encompassed by tenant plug loads in high rise buildings, aside from certain lighting that may be under the building owner�’s control.

6.2.2. Position of BOMA In replying to TURN, BOMA argues that the terms of the MM settlement

are clear and Commission has a clear basis for concluding that adoption of the

settlement is preferable, as a matter of public policy, to maintaining the present

flat rate regime for high-rise commercial building tenants.

BOMA replied as follows to specific questions posed in TURN�’s comments

on the MM settlement:

1) Could the building owner charge any volumetric rate so long as the total bill is less than what PG&E would have charged the customer? Answer: The simple language of the proposed Rule 18 states the following: “...commercial building tenants will be billed at the same rate as the master meter billed by PG&E under the CPUC approved rate schedule servicing the master meter” The building owner can only charge the volumetric rate that is charged to the master meter customer.

2) How will the building owner allocate demand charges, as opposed to energy charges for tenants? Answer: Under the proposed Rule 18, demand charges must be allocated to tenants in accordance with their measured coincident demand.

3) Must the submeters be TOU or other advanced meters?

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Answer: To meet the requirements of the proposed Rule 18, the submeters must have the capability to provide the same billing measurements as the master meter serving the building.

4) Will common area usage be allocated, or simply the usage under the tenants control? Answer: To be consistent with the proposed Rule 18, all common area usage will be metered and allocated across all tenants in accordance with leases and recovered through rent.

5) What would happen in a building where some tenants agreed to submetering, but others either refused, or where some leases had yet to expire and be subject to the modification? Answer: To be consistent with the proposed Rule 18, all metered customers would be billed in accordance with the master meter tariff. A bill would be calculated for the metered common areas in the same way and the common areas bill would be allocated across all customers in accordance with leases and recovered through rent as is done today. The balance of the building metered usage would be allocated to the non-metered customers as specified in their leases.

As TURN suggests, regardless of when meters are installed, an individual tenant will not be assessed metered energy charges by the building owner until the tenant has agreed to the same by executing a lease.

6) What would stop the building owner from collecting more from tenants than charged by PG&E, when costs allocated by submetering were collected from some tenants, in addition to costs allocated on a square-footage basis to other tenants? Answer: To do so would violate the Rule 18 requirement that tenants be billed at the same rate as the master meter. It would also violate cost pass through terms of leases and subject the building owner to civil action. The total collected by the building owner for energy charges from tenants (regardless of how calculated) may not exceed that billed to the master meter customer. The change in Rule 18 would not make cheating by building owners any more likely than under the current Rule.

7) How much could building owners charge for hardware, software, O&M and administrative costs associated with submetering? Answer: Paragraph 9 of the proposed Settlement refers to owners charging for “costs” of the metering and information services, according to terms jointly agreed to by tenants and owners and specified in leases. The costs for such services will likely vary by the effort required to provide the services and are optional for the tenant. As a practical matter, the need of the building owner to remain competitive will limit the building owner’s expenses for such items.

8) What would protect tenants from paying twice for meter and billing-related O&M and administrative costs-once through the PG&E charges for these same services allocated to tenants, and a second time though the separate charges from the building owner?

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Answer: The charges for PG&E’s master meter customer charge would be allocated across all tenants. The charges for additional submetering and information services charges would be billed to those customers who elect to take the service. There would be no double charge as asserted.

9) What kinds of information would tenants receive in bills from building owners? Answer: The bills would have the same level of detail as the master meter bill from PG&E, as required for billing the customer in accordance with the same rate as the master meter for the tenant metered portion of the bill. The bill would also show the customer’s square footage allocation of common area charges. In addition to billing data, information services could be available for virtual real time tracking of customer and building energy usage and costs to assist the tenant in managing energy costs.

In replying to TURN�’s arguments, BOMA states (a) the proposed MM

settlement requires that tenants be charged for electricity in accordance with the

rate schedule that applies for the master meter and no more; (b) the MM

settlement allows building owners to recover the costs of providing metering and

information service and no more; (c) building owners will not make a profit on

the allocation of the costs of electricity nor on the optional metering and

informational services; (d) tenants will benefit from the MM settlement to the

extent that they are able to better manage their load and reduce costs; (e) tenant

efficiency helps owners achieve exceptional building energy efficiency, become

more competitive and build asset value; and (f) more efficient buildings also

benefit ratepayers by reducing overall system demand and flattening load

curves.

Regarding TURN�’s concern that the MM settlement leaves to the

submetered high-rise tenant and the building owner the resolution of any

disputes concerning the billing and measuring of electricity, BOMA responds

that it is a feature of other landlord provisioned and measured utility services.

According to BOMA, similar provisions are embraced in Commission-mandated

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provision of telecommunications,15 water service,16 and residential gas and

electric service.17

Regarding TURN�’s statement that allocating to tenants a �“proportional

share�” of the costs of load within the building owner�’s control will not promote

demand response or increased efficiency in those loads, BOMA states that TURN

misses the point of the proposal. According to BOMA, the real objective of the

settlement proposal is to help tenants manage the energy use under their direct

control. There has been no suggestion whatever that the MM settlement will

make any significant change in the efficiency of energy use in the common areas

of commercial buildings. Furthermore, electricity costs for common areas are

currently allocated to tenants and will continue to be allocated in the same way

with or without the settlement. To the extent that submetering makes tenants

more aware of energy costs they may be inclined to be more conscious about

common area use but any effect would probably be marginal.

Regarding TURN�’s allegation that submetered tenants may not receive

dynamic price signals at all under the MM settlement, because some eligible high

rise buildings take service under Rate Schedule A -10, which is not even a TOU

Rate Schedule, BOMA points out that most all of the eligible buildings are under

E20, or E19, with a few possibly on A10. Also, all A10 customers with demand

15 D.87-01-063, 23 CPUC 2d 554, 571 (Guideline 13. �“Any billing disputes by tenants or joint users shall be taken up with the provider not with the utility or the Commission.�”)

16 D.01-05-058 (unless an apartment building is deemed a public utility, �“then water service disputes are landlord/tenant issues subject to local rent control authorities and the rent control ordinance applies, or to the jurisdiction of the civil courts�”).

17 D.05-05-026 permits residential customers to complain to the Commission (because Section 739.5 requires the Commission to entertain such complaints) but does not require or authorize the serving utility to entertain or resolve such disputes.

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over 200KW are required to be on A10 TOU, and any building that chooses to

implement submetering would have options to be billed under a TOU schedule.

Regarding TURN�’s arguments that the MM settlement will not likely

capture significant demand response, BOMA states that the settlement does not

suggest any level of demand response will be achieved, but strives to create

opportunities for tenants to embrace demand response and efficiency. BOMA

points to the first two terms of the MM settlement, which state:

1) PG&E and BOMA agree that it is in the public interest that commercial building tenants receive price signals and have the opportunity to participate in dynamic pricing and energy conservation programs.

2) PG&E and BOMA agree that it is in the public interest that building owners participate in dynamic pricing and energy conservation programs, and BOMA will encourage its membership to do so, and to timely pass on to commercial tenants dynamic pricing and energy conservation options and incentives that become available.

6.2.3. Discussion The record upon which we must determine the reasonableness of the MM

Settlement consists of BOMA�’s prepared testimony (Exhibit 8), the proposed MM

Settlement, TURN�’s Comments in Opposition to MM settlement,18 PG&E�’s Reply

to TURN�’s Opposition, and BOMA�’s Reply to TURN�’s Opposition.

In its comments, TURN has raised legitimate issues and questions related

to the reasonableness of the settlement. While the replies of BOMA and PG&E

adequately address many of TURN�’s concerns, imposition of certain conditions

18 While TURN opposed the MM Settlement Agreement, they did not request hearing or the opportunity to present testimony as provided by Rules 12.2 and 12.3 of the Rules of Practices and Procedure.

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A.06-03-005 ALJ/DKF/hkr/sid related to monitoring and customer information are necessary to support a

finding that the settlement is reasonable in light of the record.

Many elements of the MM settlement agreement are reasonable. First, as a

matter of policy, it is important for commercial building tenants to receive

appropriate price signals and to have the opportunity to effectively use dynamic

pricing options and participate in energy conservation programs. We

understand that the extent of any related energy savings is questionable. BOMA

estimates its members alone manage 600 million square feet of office space and

estimates a related maximum demand of approximately 3,500 to 4,000 MW.

However, BOMA indicates that tenants may control only 30% to 40% of the

energy consumed in commercial buildings and TURN notes that demand

elasticity may only be in the range of 1.5% to 9.1% based on the California

Statewide Pricing Pilot�’s findings. Furthermore, implementation of any master

metering, including changes to lease terms and installation of submeters and

associated equipment, will take time. Even so, the evolution from essentially flat

rate electric billing with no incentive for tenants to control their use to a system

where tenants can cost effectively manage energy use under their direct control

provides persuasive reasoning when evaluating the overall reasonableness of the

MM settlement.

Second, tenants would be appropriately billed for the usage under their

direct control. The building manager can only charge tenants the volumetric rate

that is charged to the master meter customer and the demand charges must be

allocated to tenants in accordance with their measured coincident peak demand.

Charges for additional submetering and information services charges would be

billed to those tenants that elect to take the service.

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Third, with respect to common load, there will be no difference in the way

tenants are billed. Common usage will be metered separately and continue to be

billed and paid in proportion to the square footage tenants occupy.

Fourth, in buildings where some tenants agree to submetering and others

either refuse or are under leases that have not yet expired, metered tenants

would be billed in accordance with the master meter tariff for their controlled

usage, common usage would be metered and allocated across all customers in

accordance with leases (generally square footage) and recovered through rent as

is done today, and the balance of the building metered usage would be allocated

to the non-metered customers as specified in their leases.

Fifth, bills from building owners for submetered tenants would have the

same level of detail as the master meter bill from PG&E. The bill would also

show the customer�’s square footage allocation of common area charges. In

addition to billing data, information services could be available for virtual real

time tracking of customer and building energy usage and costs to assist the

tenant in managing energy costs.

Sixth, the MM settlement provision that leaves the resolution of any

disputes concerning the billing and measuring of electricity to the submetered

tenant and the building owner is comparable to that for other landlord

provisioned and measured utility services for telecommunications, water, and

residential gas and electricity.

However, in considering the reasonableness of the settlement, we agree

with certain of the concerns raised by TURN. The ultimate cost to commercial

tenants, especially compared to what is now embedded in rent, whether or not

commercial tenants will actually be afforded opportunities to more efficiently

meet their electricity needs, and whether or not commercial tenants will actually

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A.06-03-005 ALJ/DKF/hkr/sid be able to more efficiently meet their electricity needs are considerations that

must be taken seriously. While BOMA indicates that its members have

incentives to keep building owner charges for electricity low, that it is in the

public interest that building owners participate in dynamic pricing and energy

conservation programs, and that BOMA will encourage its members to so, there

is little on the record that quantifies the effect of building owner charges for

meters, meter reading and billing services or quantifies the potential dynamic

pricing and energy conservation effects and savings that might accrue under the

MM settlement. Rather than dismissing or delaying commercial building master

metering because of these concerns, which may or may not evolve into actual

problems, we would rather monitor the program as it develops and then address

any actual problems as needed. To this end, we condition adoption of the

settlement on the following reporting requirement.

For PG&E�’s next Phase 2 GRC, PG&E and BOMA should conduct a

statistically significant survey regarding commercial building master metering

experience to date, in order to answer the following questions:

1) How many commercial buildings managed by BOMA members in PG&E�’s service territory provide submetering options to its tenants? What percent of commercial buildings managed by BOMA members in PG&E�’s service territory does this represent?

2) What is the approximate total building demand associated with commercial buildings managed by BOMA members in PG&E�’s service territory that provide submetering options to their tenants?

3) Were there any noticeable changes to total building usage and usage patterns after the implementation of commercial submetering? Can those changes be quantified? If so, what are the results?

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4) What were the actual monthly meter, meter reading and billing charges for submetered service that were billed to submetered customers?

5) How were the monthly meter, meter reading and billing charges determined and calculated?

6) Were the monthly meter, meter reading and billing charges determined and calculated consistently by building owners?

7) How do the building owner charges for the monthly meter, meter reading and billing compare to what PG&E would charge for the same activities?

8) How do submetered tenants�’ total bills (metered plus common allocation) compare to what would have been charged under the previous square footage allocation for the entire bill?

9) For submetered tenant charges, including those related to metered energy use, allocated demand charges and landlord determined charges for meters, meter reading and billing, how do commercial tenant bills compare to what PG&E would have charged a customer for direct service on an appropriate comparable tariff schedule?

10) What types of guidelines and help, if any, were provided to building owners by BOMA or PG&E regarding meter installation, meter O&M, meter reading, and billing?

11) What types of problems were experienced by building owners with regard to meter installation, meter O&M, meter reading, and calculating bills? How were those problems reconciled?

12) To what extent did building owners provide appropriate information to their submetered tenants relating to available dynamic pricing options and energy efficiency programs, including those programs requiring landlord assistance in order to participate?

13) To what extent did commercial tenants participate in dynamic pricing and energy efficiency programs, including those programs requiring landlord assistance in order to participate?

14) How can commercial building master metering be improved?

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Information provided in response to these questions will then be evaluated

by the Commission and appropriate action will be taken as needed.

6.3. Alternative Terms and Conditions TURN advocates rejection of the MM settlement. However, TURN also

offers the following modifications to address some (but not all) of the

shortcomings of the Settlement identified above, in the event that the

Commission intends to adopt the settlement. In that case, TURN strongly

recommends that the Commission�’s adoption of the MM settlement be

conditioned upon the acceptance of alternative terms. Those alternative terms,

BOMA�’s response to the need for them,19 and our resolution of conflicting views

follow.

6.3.1. Common Loads Should Not Be Allocated To Tenants

TURN recommends that the MM settlement be modified to prohibit the

use of submeters to allocate common costs to tenants. According to TURN,

tenants have no control over common loads, and the incentive to minimize and

control these loads should remain with the entity that controls common loads:

the building owners.

BOMA states that submeters will not be used for this purpose. Costs

related to common load will be allocated to tenants consistent with the current

practices of allocating costs, typically on a square footage basis.

19 PG&E, the other party to the settlement, replied to TURN�’s alternative terms by emphasizing that since it has no customer relationship with submetered tenants and has no role in the commercial agreement between landlord and its tenants, PG&E cannot be responsible for enforcing requirements proposed by TURN as detailed in this section of the decision.

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To the extent that it is not clear in the MM settlement, we clarify that

submeters shall not be used to allocate common costs to tenants.

6.3.2. Submeters Should Provide at Least the Same Information as the Master Meter

In order to facilitate accurate bill calculation at the same rates charged by

PG&E to the master meter, TURN recommends that the settlement be modified

to make it clear that building owners who install submeters should be required

to install submeters with at least the same degree of sophistication as the master

meter. For instance, if the master meter is a TOU meter, the submeters should

have the same capabilities. If PG&E upgrades the master meter for purposes of

applying a more �“dynamic�” or �“advanced�” rate schedule, the submeters should

likewise be updated.

We agree with BOMA�’s response that this requirement is already implicit

in the proposed modification of Rule 18 for submetered bills to be calculated

using the same tariff as the master meter. The need for submeters to provide at

least the same information as the master meter is clear.

6.3.3. Tenants Should Be Provided With the Same Information Currently Provided to Residential Submetered Tenants by the Utility and the Master Meter Customer Pursuant to D.04-11-033 and D.05-05-026

In D.04-11-033 and D.05-05-026, the Commission placed several

requirements on residential landlords who submeter their tenants�’ usage, as well

as on the serving utility, to provide such tenants with basic consumer

protections. TURN argues that the MM settlement should be modified to

incorporate similar requirements. First, as a general matter, building owners

installing submeters should be required to provide all tenants with the following

information: (1) the PG&E rate schedule serving the master meter; (2) the contact

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A.06-03-005 ALJ/DKF/hkr/sid information for PG&E; (3) the contact information for the Commission�’s

Consumer Affairs Branch; and (4) the contact information for the California

Department of Food and Agriculture, Division of Measurement Standards, who

is responsible for regulating measuring devices, including submeters, by testing

for accuracy, evaluating suitability of devices for installation and use, and

reviewing billing, pricing, and metering complaints.

Additionally, TURN recommends PG&E should be required to respond to

inquiries from submetered commercial tenants, as required of the utility by

D.04-11-033 for residential submetered tenants. PG&E should at least provide

information about the rate schedule applied to the master meter, and explain

how it calculates its bills on that rate schedule, since the building owner must

allocate energy costs at the same scheduled rate as billed by PG&E to the master

meter. PG&E should additionally refer the tenant to the Commission�’s

Consumer Affairs Branch, for resolution of complaints, if the tenant and building

owner cannot reach resolution.

Finally, TURN recommends the MM settlement should require building

owners to clearly notify tenants that energy charges will be removed from rent

when submetering commences. PG&E explains that under the settlement, �“The

master-meter customer should simultaneously be removing from rent the

corresponding submetered charges,�” but �“PG&E will not be monitoring this

activity.�” To provide tenants with an opportunity to detect a problem, TURN

argues that PG&E should be required to notify a master meter customer

installing submeters that the customer must notify tenants that they are entitled

to have energy charges removed from rent when submetering commences. This

requirement would be consistent with the requirement adopted by the

Commission in D.05-05-026 for residential submetering.

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BOMA indicates that it intends to make available as much information as

possible that can assist tenants in understanding and managing their energy

costs. BOMA also agrees that tenants should be informed about how to contact

the Division of Measurement Standards and others for dealing with any issues of

meter accuracy, etc, that may arise. However, BOMA asserts that there is no

need to modify the settlement, since there is already a body of State law that

provides consumer protections.

6.3.3.1. Discussion TURN�’s recommendation that tenants should be provided with the same

information currently provided to residential submetered tenants pursuant to

D.04-11-033 and D.05-05-026 is generally reasonable. Knowing the rate schedule

of the master meter and contact information that might be of assistance in

addressing meter, meter reading or billing problems is essential and we will

require such information be made available to commercial tenants. In response

to BOMA, we note that having consumer protections in a body of State law may

be much different than tenants knowing the protections exist at all and knowing

who to contact when problems arise.

In its reply to TURN�’s comments, BOMA points out that the Department

of Food and Agriculture has set up a complaint procedure using the offices and

persons of the county sealers as contact points through which customers may

complain about their meters. Building owners should provide tenants the

appropriate contact information for this process.

The proposed requirement for PG&E to respond to inquiries from

submetered commercial tenants, even if only in a general sense, provides some

assurance that commercial tenants will have reasonable means to examine how

fairly they are being treated by their landlords. For instance, having PG&E

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available to explain how bills are calculated provides a reasonable means for

commercial tenants to verify their submeter bills.20

We will not require building owners to provide contact information for the

Commission�’s Consumer Affairs Branch. As indicated previously, disputes

concerning the billing and measuring of electricity are to be resolved between the

tenant and landlord. PG&E should be able to assist tenants in understanding

how their bills should be calculated consistent with the clarifications provided in

this decision.

We do agree that it is important that tenants be notified that they are

entitled to have tenant controlled energy charges removed from rent when

submetering commences.21 However, rather than requiring PG&E to notify a

master meter customer installing submeters that the customer must notify

tenants that they are entitled to have energy charges removed from rent when

submetering commences, we will impose that requirement directly on the

building owner. That information should be provided along with the other

information that the building owner must provide to its submetered tenants.

Besides these requirements, we will add that the building owner should

provide sufficient information and guidance for their submetered customers to

be able to replicate and verify their total bills. Additionally, the building owner

should provide information on dynamic pricing options and all energy efficiency

programs that are relevant to its submetered customers, including those

20 We note PG&E�’s assertion that commercial submetered tenants are not and will not be entitled to information about their landlord�’s utility bill under Commission policies on an individual customer�’s information. Access to confidential customer information is not necessary under TURN�’s proposal.

21 See D.05-05-026, mimeo., pp. 16 -17.

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A.06-03-005 ALJ/DKF/hkr/sid programs that require landlord assistance for participation. Both conditions

slightly expand on MM settlement terms, provide more explicit expectations on

our part and are consistent with BOMA�’s stated intention to make available as

much information as possible that can assist tenants in understanding and

managing their energy costs.

6.3.4. PG&E Should Allow Submetering Only Where the Master Meter Customer Meets Certain Requirements

The MM settlement would modify PG&E�’s Rule 18 to permit any

commercial customer receiving electric serve at an eligible high rise office

building to install submeters, so long as the owner charges the tenants at the

same rate as PG&E bills the master meter. TURN recommends that each of the

following conditions be added to those proposed by PG&E and BOMA as

modifications to Rule 18.C.2.b.

(a) It is impractical for PG&E to separately bill each tenant.

(b) The master meter customer has participated in PG&E�’s energy efficiency programs or has otherwise implemented all cost-effective energy efficiency retrofits to the building, not including equipment solely within the possession of and maintained by tenants.

(c) Each tenant has control over the majority of her or his electric energy use.

(d) Substantial energy conservation will be effected by submetering.

(e) The master meter customer takes service on a �“dynamic pricing�” PG&E rate schedule.

BOMA is in agreement with item (a) which replicates conditions already

stated in Rule 18.C.2.c and item (e) since all buildings with demand in excess of

200 KW must be on a TOU schedule. With respect to items (b), (c) and (d),

BOMA argues that TURN has made no case as to how the requirements would

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A.06-03-005 ALJ/DKF/hkr/sid enhance the potential for fulfilling objectives under the proposed settlement or

what the requirements would accomplish.

In this instance, we agree with BOMA. Items (a) and (e) are important but

are already sufficiently addressed such that there is no need to modify the

settlement. Regarding Item (b), we encourage customers to participate in all

available cost effective energy efficiency programs, but see no reason or logic in

penalizing tenants by withholding the option to obtain submetered service and

the opportunity to better manage their usage solely because the landlord did not

pursue every energy efficiency option. Regarding (c), BOMA makes a valid

point. Without submetering it is impossible to know what portion of a tenant�’s

usage relates to submetered usage and what portion relates to common usage.

Item (d) is, in general, a desired result but the chances of achieving that result are

not specifically known and may not be known until the energy efficiency

measures are actually pursued. In this case, rather than guessing as to what

portion of usage is under the control of a tenant or how much energy efficiency

can be obtained, we feel it is more appropriate to provide commercial tenants

with the opportunity to participate in dynamic pricing and energy efficiency

programs and to provide proper incentives to make the programs successful.

There is always a possibility that commercial building master metering may fail

to provide the envisioned benefits, but it is in the public interest to put our best

efforts into effect now rather than later. We note that this is an area that would

be monitored under the reporting requirement condition that was previously

specified and discussed.

6.4. Consistency with Law TURN asserts that the MM settlement is inconsistent with the law in that it

contradicts the spirit, if not the letter, of D.63562 and D.92109, which adopted

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A.06-03-005 ALJ/DKF/hkr/sid and reaffirmed the prohibition on commercial submetering and ignores the

Commission�’s prior directives in D.99-10-065 and D.05-05-026 regarding the

procedural vehicle and issues to consider if and when the Commission

reconsiders commercial submetering.

BOMA argues that D.63562 and D.92109 have not aged well in an era of

technological advances and are not entitled to the veneration TURN seeks for

them. BOMA also states D.99-10-065 is not the logical offspring of D.63562 and

D.92109 that TURN suggests.

We find that the MM settlement, as conditioned by our decision today, is

consistent with law. We analyze each of decisions cited by TURN below. In

summary, while the MM settlement imposes a result (authorization of

commercial submetering) that is different than the results of D.63562 and

D.92109, (prohibition of commercial submetering), the Commission�’s reasons for

prohibiting commercial submetering are no longer applicable or are now

sufficiently addressed by the terms of the conditioned MM settlement. That is,

when evaluated in terms of what concerned the Commission in D.63562 and

D.92109 and led to the prohibition of commercial submetering and reaffirmation

of the prohibition, the MM settlement, with the conditions discussed above, is

consistent with those decisions. In D.99-10-065, the Commission described

certain issues requiring further thought before it would decide to modify the

commercial submetering prohibition. As described below, after consideration of

those issues, we feel comfortable moving forward with the program. In

D.05-05-026, the Commission offered but did not mandate the rulemaking

process for parties to pursue commercial submetering. Commercial submetering

can also be addressed in a utility specific proceeding. Either method is consistent

with law.

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6.4.1. D.63562 In 1962, the Commission issued D.63562, barring nondomestic customers

from billing their tenants for electricity based on submetering other than for

domestic use or by municipalities or other public utilities purchasing utility

service under wholesale schedules designed for resale purposes. The

Commission authorized this change in policy after concluding that elimination of

nondomestic submetering was in the public interest.

Prior to that decision, PG&E had the right to either grant or deny resale

privileges to a customer. The purpose of changing Rule 18 at that time was to

clarify the intent and set forth more clearly PG&E�’s practice thereunder. PG&E

maintained that the intent of, and practice related to, the then-current Rule 18

was to prohibit resale by submetering other than for domestic use or by

municipalities or other public utilities purchasing utility service under wholesale

schedules designed for resale purposes. There were, however, some customers

who had been permitted to resell electricity or gas to commercial tenants by

submetering. This had been allowed when the convenience of PG&E, type of

service, or other considerations indicated that no substantial adverse effect

would accrue to PG&E or to its ratepayers generally.

At the time PG&E made that request it had 15 requests for nondomestic

resale by submetering of which 8 involved requests to change from direct

metering to master metering and resale through submeters. PG&E�’s principal

concern appeared to be potential substantial revenue loss which presented a real

and present danger of adversely affecting PG&E and its existing and future

ratepayers in a manner not consistent with the public interest.

Also, according to Commission staff at that time, elimination of

nondomestic submetering was desirable and the practice of permitting master

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A.06-03-005 ALJ/DKF/hkr/sid metering was not in the public interest, because it puts an unregulated person

into the utility business and affords no recourse to the ultimate consumer either

as to rates or as to conditions of service.

Regarding PG&E and Commission staff concerns regarding rates and

revenues, under the terms of the MM settlement whereby the cost of electricity

allocated to commercial building tenants will be billed at the same rate as the

master meter billed by PG&E, revenues to PG&E would not be affected by

submetering for reasons other than changed usage behavior of tenants

implemented as a result of having the opportunity to directly benefit from the

changed behavior. Such a result is consistent with the public interest.

It is not clear what the Commission staff�’s concern was with respect to

consumer recourse as to conditions of service. However, based on the discussion

concerning the reasonableness of the settlement, we believe the commercial

tenants subject to submetering are reasonably protected as to:

How they are put on such service.

How they will be billed for such service.

How complaints regarding service will be addressed.

Based on consideration of the intent of PG&E in requesting modification to

Rule 18 in 1962 and the reasons for requesting the modification, reinstitution of

submetering for commercial customers is not inconsistent with D.63562 because

concerns regarding rates and conditions of service have been addressed and

alleviated by the terms of the conditioned MM settlement.

6.4.2. D.92109 The Commission reconsidered the issue of commercial submetering in

D.92109, issued in 1980. In that proceeding, two commercial customers of PG&E

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A.06-03-005 ALJ/DKF/hkr/sid filed an application with the Commission for authority to deviate from PG&E�’s

submetering rules. In denying applicants�’ request, the Commission stated:

The reasons for invoking the restriction against nondomestic submetering appear to be as valid today as they did in 1962. Use of PG&E's trained personnel does assure a uniformity of meter reading, billing, and adjustments. Being headquartered in Illinois would require an employee of EMC to travel to the shopping centers once a month for the purpose of reading meters. All bills would be prepared in Illinois and mailed to the tenants in California. The usual problems relating to meter reading, the testing and repair of meters, billing, and the processing of disputed bills would be compounded because of the geographical distance between EMC and the tenants.

Even this geographically remote service would be jeopardized if the funds generated by submetering failed to produce a profit. The record is silent on what service would be provided if EMC failed to perform. According to applicants' proposal, EMC�’s compensation would be determined by a formula upon a percentage of the profits derived from the resale of electricity. When preparing their revenue and cost estimates, applicants gave no consideration to time-of-use rates, and the record clearly demonstrates that with time-of-use rates there would be no profit. Unless some suitable arrangement could be made between applicants and EMC an alternative service would have to be made available. In either event, there would be no regulatory accountability that would ensure consistent maintenance of suitable operating standards and billing practices.

We believe that metering of individual end users has a beneficial effect on the conservation of energy, but these benefits would be greatly offset by a variety of potential problems that could arise if the resale of energy by submetering was authorized for nondomestic customers. We believe that direct metering by PG&E would be the best way to achieve conservation and at the same time assure applicants' tenants of a uniform and reliable standard of service. But, in the absence of a rule change eliminating the provision for master metering where the charge to tenants is absorbed in the rental of the premises, the only way that this can be accomplished is by way of

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mutual agreement between applicants and PG&E. We strongly suggest that the parties work toward this end.22

TURN cites D.92109 to support its claim that the MM settlement is

inconsistent with law. However, D.92109 bases much of its reasoning for

rejecting commercial submetering on D.63562. In our above discussion of

D.63562, we determined that reinstitution of submetering for commercial

customers is not inconsistent with D.63562 because concerns regarding rates and

conditions of service have been addressed and alleviated by the terms of the

conditioned MM settlement. That alleviates much of our concern with the MM

settlement when reviewed in light of D.92109.

In D.92109 the Commission also expressed concern with the geographical

problem of having an Illinois based company providing the meter reading and

billing services. We would expect that in general building owners would solicit

the most cost effective services and that technology advances since 1980 would

address at least some of the concerns of using out-of-state services. Nonetheless,

we are interested in the costs and charges related to these services since they will

essentially be unregulated charges to the submetered tenants. As discussed

earlier, for monitoring and evaluation purposes, we have conditioned adoption

of the MM settlement with a requirement that PG&E and BOMA provide certain

information in the next rate design proceeding. Some of that information

pertains specifically to the costs of meters, meter reading and billing.

D.92109 also mentions a concern with submeter accuracy and reliability.

In its reply to TURN, BOMA notes the state statutes and regulations that address

22 Application of H.A.R.T Properties and Sun Valley (1980) 4 CPUC 2d 179, 186.

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the testing and installation of non-utility electric meters.23 As an attachment to

its reply, BOMA also provided a written description and explanation of the

scheme of regulation that exists to protect commercial customers served through

electric energy submeters. This includes general regulation of all measuring

instruments as well as regulation of service agencies that might install and repair

electrical energy submeters. Such evidence alleviates our concern on this topic.

For the above stated reasons, we determine that the conditioned MM

settlement is consistent with law when viewed in light of D.92109.

6.4.3. D.99-10-065 In D.99-10-065, the Commission addressed issues related to distributed

generation and electric distribution competition. Although the focus of the OIR

was principally on distributed generation and distribution competition, the OIR

also solicited comment on whether there should be a broader more

comprehensive review of the utility distribution company (UDC) and what the

ultimate role of the UDC should be in a restructured electric industry. As part of

this discussion, the Commission noted the desire of some parties for the

Commission to reassess restrictions on commercial building submetering.

The Commission in D.99-10-065 commented on a number of issues raised

by commercial submetering that would require further thought before the

Commission would decide to modify the commercial submetering prohibition.

TURN notes two issues in particular, as follows:

Second, we should determine if the submetering technology is capable of providing accurate and reliable meter usage data. Such

23 BOMA cites California Business & Professions Code Sections 12200-12203; 12240, 12500.10, 12505-6, 12510, & 12531 and Title 4 California Code of Regulations, Sections 4027, 4080-1 and 4085-6.

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an inquiry could include whether meter design specifications are needed for submeters. Also, some coordination with local governmental agencies, who are responsible for the accuracy of weights and measures, may be needed to ensure that any submeters used by a property owner remain accurate.

Third, if submetering is permitted, the Legislature should consider whether amendment of § 739.5 is necessary to ensure that the submetered tenants of commercial buildings are billed at the same rate that the property owner pays for the electricity. That is, should all of the cost savings or discounts that the property owner receives from the utility be passed directly through to the submetered tenant? If on-site distributed generation is used to generate electricity for the building tenants, the Legislature may need to consider what rate the submetered tenants should be charged. Consideration of how much submetered tenants should be charged would help resolve some of the concern that the UDCs raised concerning the creation of an unregulated private distribution system.24

TURN notes the concerns regarding meter accuracy and reliability as well

as billing and cost allocation to submetered tenants were consistent with the

concerns that had persuaded the Commission in D.63562 and D.92109 that

commercial submetering was not in the public interest.

Our discussion of D.92109 addresses the statutes and regulations that

govern non-utility meter installations and testing. Regarding the amendment of

Section 739.5, BOMA suggests that the legislature and Commission will want to

benefit from experience before deciding whether to seek new legislation or

impose additional restrictions. From our standpoint, we agree with BOMA, as

evidenced by our condition to the MM settlement that requires certain

information related to submeter rates be provided in PG&E�’s next GRC rate

design proceeding.

24 D.99-10-065, 3 CPUC 3d 151, 184.

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Therefore, while the Commission expressed concerns related to

submetering in D.99-10-065, the particular concerns identified by TURN have

been satisfactorily reconciled with the terms of the MM settlement as conditioned

by our decision today.

6.4.4. D.05-05-026 On August 26, 2004, the National Submetering and Utility Allocation

Association filed a petition for rulemaking, P.04-08-038, requesting that the

Commission open a rulemaking to consider rule changes to permit owners of

existing master-metered multi-unit residential buildings to submeter electricity

and natural gas service to individual tenants. The petition identified two types

of buildings that could fall into this category, multi-unit residential buildings

constructed before December 1981 and buildings constructed at any point in time

for a commercial purpose that have since been converted into a multi-unit

residential purpose. The petition also requested that the Commission consider

allowing building owners/operators to submeter service to non-residential

customers but did not pursue this second request in significant detail. BOMA

had filed a petition to intervene, on March 17, 2005, to address solely the

question of allowing submetering in commercial buildings. Because of the lack

of development of this issue by petitioner, the Commission, in D.05-05-026,

denied up front the request to open a rulemaking on the commercial property

issue and focused solely on the issue of submetering as it relates to existing

multi-unit residential buildings. The Commission also denied BOMA�’s petition

to intervene. However, BOMA, or any other interested party, was invited to file

a petition for rulemaking, if it so desired, to pursue this topic. Because of this

invitation to file a petition for rulemaking, TURN suggests the MM settlement is

inconsistent with law because the topic of commercial submetering was pursued

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through a utility specific application rather than through a rulemaking. We

disagree.

D.05-05-026 did not preclude the issue of commercial submetering from

being raised in utility specific proceedings, nor did it discuss the relative merits

or preferences related to the different forums. A rulemaking is one type of

proceeding by which we can consider commercial submetering issues. However,

moving forward in a specific utility proceeding is also a valid option, and we

choose to do so now with PG&E, because providing commercial tenants with the

opportunity to engage in dynamic pricing and energy efficiency programs in a

timely manner is important from a policy perspective. This is especially true in

light of the Energy Action Plan�’s statement of continued support of the loading

order that identifies energy efficiency and demand response as the State�’s

preferred means of meeting growing energy needs.25

TURN has raised valid concerns with the commercial submetering

proposal, but BOMA has responded adequately to most of those concerns. We

feel comfortable moving forward now, with certain conditions as discussed

above. Problems or new issues may arise over time, but they can be addressed in

subsequent proceedings. Experience gained through PG&E�’s program may be

valuable in formulating such programs for SCE and SDG&E. We see no reason

why uniformity in commercial master metering cannot be achieved over time

through utility specific proceedings. For instance, D.63592, the 1962 decision that

prohibited commercial submetering for PG&E customers was done in a PG&E

specific proceeding. A result of the Commission adopting PG&E�’s proposal in

25 See Energy Action Plan II, p. 2.

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that proceeding was �“...uniformity with the language of similar rules of the other

major utilities in California will be more nearly achieved,�”26

6.5. The Public Interest PG&E and BOMA state that by resolving the master meter issues raised in

PG&E�’s application, the settlement agreement saves the Commission and parties

from the time, expense and uncertainty associated with litigating these issues

and is thus in the public interest.

TURN argues that the settlement is not in the public interest because it

serves the interests of commercial building owners alone, harms commercial

tenants and does not meaningfully benefit commercial tenants or PG&E

ratepayers.

6.5.1. Discussion We find that the MM settlement, with conditions, is in the public interest.

The public interest of commercial master metering is broad and lies in providing

commercial tenants with the opportunity to better manage their loads and reduce

costs. Also, overall reduction of system demand and flattening load curves are in

the interest of ratepayers at large. As indicated previously, the public policy

considerations are persuasive in our actions related to approving this settlement.

We have imposed certain reporting requirements and consumer protections as

conditions for adoption of the settlement. These conditions provide assurance

that the settlement is both reasonable and in the public interest.

6.6. Conclusion on Master Meter Settlement As discussed above, we find reasons to condition the MM settlement. For

consumer protection purposes, we require the building owner and PG&E to

26 D.63562, 59 CPUC 547, 551.

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A.06-03-005 ALJ/DKF/hkr/sid provide certain specific information to submetered tenants. Also, in order to

monitor and evaluate the commercial submetering option, we require PG&E and

BOMA to provide certain information in PG&E�’s next GRC rate design

proceeding. With these conditions, the MM settlement is reasonable in light of

the record, consistent with law, in the public interest and should be adopted.

In their comments on the August 7, 2007 proposed decision (PD), both

PG&E and BOMA agreed to the conditions specified in Conclusion of Law 2.

The conditioned MM Settlement will therefore be adopted.

To comply with Conclusion of Law 2, BOMA will conduct surveys of its

members to gather the information necessary to answer the questions in

Section 6.2.3 and will work with PG&E to process, analyze, and present the

survey information (plus relevant building load data from PG&E) in PG&E�’s

next Phase 2 GRC. Also, BOMA will work with PG&E to develop an

informational packet that will be provided to BOMA Members specifying the

detailed requirements of building owners to provide tenant information as

specified in Findings of Fact 12 and 13, plus details concerning tenant electricity

cost allocation and billing in accordance with the new Rule 18 and the PD.

7. Comments on Proposed Decision The PD of the ALJ in this matter was mailed to the parties in accordance

with Section 311 of the Public Utilities Code and comments were allowed under

Rule 14.3 of the Commission�’s Rules of Practice and Procedure. Comments were

filed on or before August 27, 2007. No reply comments were filed.

PG&E filed comments on behalf of the Settling Parties, and BOMA filed

separate comments on the MM Settlement issue. The comments address MM

Settlement conditions and request that the PD be adopted with certain minor

modifications. Where appropriate, changes have been made to the PD.

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Regarding implementation of rate changes, the PD specified an effective

date on or after November 1, 2007. In comments, PG&E indicates that it will

consolidate most Phase 2 changes with the Annual Electric True-Up (AET) for

implementation on January 1, 2008.27 This approach both minimizes the number

of electric rate changes and allows the Phase 2 rate change to take place in the

context of more extensive changes to rates contemplated in the AET. Further, by

timing its Phase 2 rate changes to coincide with the projected elimination of the

Fixed Transition Amount on January 1, 2008, PG&E hopes to reduce the effect of

the increased allocation of costs for residential and small commercial customers

associated with the settlement agreements. PG&E�’s proposal is reasonable and

consistent with the intent of the PD.

8. Assignment of Proceeding

Rachelle B. Chong is the assigned Commissioner and David Fukutome is

the assigned ALJ in this proceeding.

Findings of Fact 1. The MCRA, residential rate design, streetlight rate design, SL&P rate

design, MLLP rate design, and agricultural rate design settlements are

uncontested all-party settlements.

2. The MCRA, residential rate design, streetlight rate design, SL&P rate

design, MLLP rate design, and agricultural rate design settlement agreements are

each reasonable in light of the record, consistent with law and in the public

interest.

27 The Settling Parties recognize that certain initiatives require employee training and/or changes to PG&E systems beyond a normal change to a rate value; that such systems and program changes will be implemented by PG&E diligently as time permits and in a manner consistent with maintaining the secure, smooth operations of the systems involved; and that some initiatives could take several months to implement.

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3. PG&E has provided a substantial amount of information on distribution

marginal costs, which describes the location of distribution projects undertaken

during the year, the cost of each project and the portion(s) of its territory the

project is intended to serve, in its workpapers and will have the same type of

information available in its next GRC proceeding. It is not necessary for PG&E to

file annual reports to provide this information.

4. The MM settlement is not an all party settlement and is contested.

5. It is important for commercial building tenants to receive appropriate price

signals and to have the opportunity to effectively use dynamic pricing options

and participate in energy conservation programs.

6. Under the MM settlement, commercial tenants would be appropriately

billed for the usage under their direct control, and common usage will be

metered separately and continue to be billed and paid in proportion to the

square footage tenants occupy.

7. Under the MM settlement, in commercial buildings where some tenants

agree to submetering and others either refuse or are under leases that have not

yet expired, metered tenants would be billed in accordance with the master

meter tariff for their controlled usage, common usage would be metered and

allocated across all customers in accordance with leases (generally square

footage) and recovered through rent as is done today, and the balance of the

building metered usage would be allocated to the non-metered customers as

specified in their leases.

8. Under the MM settlement, bills from commercial building owners for

submetered tenants would have the same level of detail as the master meter bill

from PG&E.

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9. The MM settlement provision that leaves the resolution of any disputes

concerning the billing and measuring of electricity to the submetered tenant and

the commercial building owner is comparable to that for other landlord

provisioned and measured utility services for telecommunications, water, and

residential gas and electricity.

10. While BOMA indicates that its members have incentives to keep building

owner charges for electricity low, that it is in the public interest that building

owners participate in dynamic pricing and energy conservation programs, and

that BOMA will encourage its members to so, there is little on the record that

quantifies the effect of building owner charges for meters, meter reading and

billing services or quantifies the potential dynamic pricing and energy

conservation effects and savings that might accrue under the MM settlement.

11. Rather than dismissing or delaying commercial building master metering

because of concerns related to building owner charges and implementation of

energy efficiency measures, which may or may not evolve into actual problems,

it is reasonable to monitor the program as it develops and then address any

actual problems as needed.

12. Commercial tenants should be provided with certain information

currently provided to residential submetered tenants pursuant to D.04-11-033

and D.05-05-026 including the following:

(a) Building owners installing submeters should provide all tenants with the following information: (1) the PG&E rate schedule serving the master meter; (2) the contact information for PG&E; (3) the contact information for the California Department of Food and Agriculture meter complaint process; and (4) notification that tenant controlled energy charges will be removed from rent when submetering commences.

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(b) PG&E should respond to inquiries from submetered commercial tenants and at least provide information about the rate schedule applied to the master meter and explain how it calculates its bills on that rate schedule.

13. Consistent with BOMA�’s stated intention to make available as much

information as possible that can assist tenants in understanding and managing

their energy costs, it is reasonable for building owners to provide the following

information to submetered tenants:

(a) Sufficient information and guidance for their submetered customers to be able to replicate and verify their total bills.

(b) Information on dynamic pricing options and all energy efficiency programs that are relevant to its submetered customers, including those programs that require landlord assistance for participation.

14. Based on consideration of the intent of PG&E in requesting modification to

Rule 18 in 1962 and the reasons for requesting the modification, reinstitution of

submetering for commercial customers is not inconsistent with D.63562 because

concerns regarding rates and conditions of service have been addressed and

alleviated by the terms of the MM settlement, as conditioned by our decision

today.

15. D.92109 bases much of its reasoning for rejecting commercial submetering

on D.63562.

16. State statutes and regulations sufficiently address the testing and

installation of non-utility electric meters.

17. While the Commission expressed concerns related to submetering in

D.99-10-065, the particular concerns identified by TURN have been satisfactorily

reconciled with the terms of the MM settlement, as conditioned by our decision

today.

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18. This issue of commercial submetering can be addressed in either a generic

rulemaking proceeding or in a utility specific proceeding.

19. The public interest of commercial master metering is broad and lies in

providing commercial tenants with the opportunity to better manage their loads

and reduce costs.

20. Overall reduction of system demand and flattening load curves are in the

interest of ratepayers at large.

21. The MM settlement, as conditioned by our decision today, is reasonable in

light of the record, consistent with law and in the public interest.

Conclusions of Law 1. The MCRA, residential rate design, streetlight rate design, SL&P, MLLP,

and agricultural rate design settlement agreements should be approved.

2. The MM settlement should be approved once PG&E and BOMA agree to

the following:

(a) In PG&E�’s next Phase 2 GRC, BOMA and PG&E will provide sufficient information, based on actual commercial building master metering experience to date, to answer the questions specified in Section 6.2.3 of this decision

(b) PG&E and building owners will be required to provide the information summarized above in Findings of Fact 12 and 13 to commercial submetered tenants.

3. This order should be effective immediately so that PG&E may prepare the

necessary advice letter, parties may review and comment on that advice letter,

and rates may be timely adjusted.

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INTERIM ORDER

IT IS ORDERED that:

1. The motions dated February 9, March 16, and May 4, 2007 which request

adoption of the marginal cost and revenue allocation settlement agreement, the

residential rate design settlement agreement, the streetlight rate design

settlement agreement, the medium and large light & power rate design

settlement agreement, and the agricultural rate design settlement agreement are

granted. The settlement agreements in Appendices B, C, D, E and F are adopted.

2. Regarding the motion dated April 27, 2007, which requests adoption of the

small light & power rate design settlement agreement, the small light & power

rate design settlement agreement, as detailed in Appendix G, is adopted. Also,

since Pacific Gas and Electric Company (PG&E) and the Building Owners and

Managers Associations of San Francisco, Greater Los Angeles, Orange County,

and California agree to the conditions specified in Conclusion of Law 2, the

commercial building master meter settlement agreement, as detailed in

Appendix H, is adopted.

3. Within 45 days of the date this order is mailed, PG&E shall file an advice

letter in compliance with General Order 96-B. The advice letter shall include

revised tariff sheets to implement the revenue allocations and rate designs

adopted in this order. The tariff sheets shall become effective on or

after November 1, 2007, subject to Energy Division determining that they are in

compliance with this order. No additional customer notice need be provided

pursuant to General Rule 4.2 of General Order 96-B for this advice letter filing.

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4. This proceeding remains open to consider future dynamic pricing tariffs

and options for PG&E.

This order is effective today.

Dated September 6, 2007, at San Francisco, California.

MICHAEL R. PEEVEY President

DIAN M. GRUENEICH JOHN A. BOHN RACHELLE B. CHONG TIMOTHY ALAN SIMON Commissioners

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63

APPENDIX F SUPPLEMENTAL SETTLEMENT AGREEMENT ON COMMERICAL BUILDING

MASTER METER ISSUES IN PG&E’S APPLICATION 06-03-005

I. INTRODUCTION

In accordance with Article 12 of the Rules of Practice and Procedure of

the California Public Utilities Commission (CPUC), the parties to this Commercial

Building Master Meter Settlement Agreement (Settling Parties, Master Meter

Settlement) agree on a mutually acceptable outcome to the commercial building

master meter issues in Application (A.) 06-03-005, Application Of Pacific Gas

And Electric Company To Revise Its Electric Marginal Costs, Revenue Allocation,

And Rate Design. The details of this Master Meter Settlement are set forth

herein.

II. SETTLING PARTIES

The Settling Parties are as follows:

Building Owners and Managers Associations of San Francisco and of

California (BOMA)

Pacific Gas and Electric Company (PG&E)

III. SETTLEMENT CONDITIONS

This Master Meter Settlement resolves the issues raised by the Settling

Parties in A.06-03-005 involving commercial building master meters, subject to

the conditions set forth below:

1. This Master Meter Settlement embodies the entire understanding and

agreement of the Settling Parties with respect to the matters described, and it

supersedes prior oral or written agreements, principles, negotiations, statements,

A.06-03-005 ALJ/DKF/hkr/sid representations, or understandings among the Settling Parties with respect to

those matters.

2. This Master Meter Settlement represents a compromise among the

Settling Parties’ respective litigation positions, not agreement to or endorsement

of disputed facts and law presented by the Settling Parties in this proceeding.

This Master Meter Settlement does not constitute precedent regarding any

principle or issue in this proceeding or in any future proceeding.

3. The Settling Parties agree that this Master Meter Settlement is

reasonable in light of the testimony submitted, consistent with law, and in the

public interest.

4. The Settling Parties agree that no provision of this Master Meter

Settlement shall be construed against any Settling Party because that Settling

Party or its counsel or advocate drafted the provision.

5. This Master Meter Settlement may be amended or changed only by a

written agreement signed by the Settling Parties.

6. The Settling Parties shall jointly request Commission approval of this

Master Meter Settlement and shall actively support its prompt approval. Active

support shall include written and oral testimony if testimony is required, briefing if

briefing is required, comments and reply comments on the proposed decision,

advocacy to Commissioners and their advisors as needed, and other appropriate

means as needed to obtain the requested approval.

7. In the event the Commission rejects or modifies this Master Meter

Settlement, the Settling Parties reserve their rights under CPUC Rule 12.4.

64

A.06-03-005 ALJ/DKF/hkr/sid IV. SETTLEMENT HISTORY

In its Test Year 2007 General Rate Case (GRC) Application 05-12-002,

PG&E proposed that the proceeding be separated into two distinct phases:

Phase 1, which would cover the revenue requirement testimony submitted with

that application, and Phase 2, which would cover electric marginal costs, revenue

allocation, and rate design. The Assigned Commissioner’s Ruling and Scoping

Memo in A.05-12-002 directed PG&E to file its marginal costs, revenue

allocation, and rate design proposals as a new application rather than as a

separate phase.

Consistent with the Assigned Commissioner’s Ruling in A.05-12-022,

PG&E filed Application 06-03-005 on March 2, 2006, related to electric marginal

costs, revenue allocation, and rate design. According to its application, PG&E’s

marginal cost, revenue allocation and rate design proposals were intended to

“continue progress toward cost based, efficient pricing, while taking into

consideration equity among customers and customer acceptance.” The

application was protested on March 27, 2006, by DRA.

A prehearing conference was held in the proceeding on May 3, 2006

before Administrative Law Judge (ALJ) Fukutome and Assigned Commissioner

Rachelle Chong. The scope of the proceeding and procedural schedule were set

forth in the Assigned Commissioner’s Ruling and Scoping Memo dated May 25.

In compliance with the Scoping Memo, PG&E updated its showing on June 26.

DRA served prepared testimony on September 13. Intervenors AECA, BOMA,

CAC, CAL-SLA, CFBF, CLECA, CLFP, CMTA-ICP, DACC, EPUC, FEA, PV

65

A.06-03-005 ALJ/DKF/hkr/sid Now, TURN, Vote Solar, and WMA served their prepared testimony on October

27.

Meanwhile, on September 20, PG&E held a meet and confer session with

all parties as well as Commission staff, as directed in the Scoping Memo. After

providing notice pursuant to Rule 12.1(b), PG&E conducted additional settlement

discussions pursuant to Article 12 of the CPUC’s rules with the active parties to

the proceeding. On November 1, PG&E held a mandatory settlement conference

pursuant to the Scoping Memo. Based on the settlement discussions, PG&E and

the Settling Parties sought extensions of the procedural schedule, which were

granted by ALJ Rulings dated November 9 and December 14, 2006.

On January 4, 2007, parties to the settlement discussions reached

agreement in principle on the terms of a Settlement respecting electric marginal

costs and revenue allocation. The following day, PG&E’s counsel notified ALJ

Fukutome that the active parties to the proceeding had reached settlement in

principle regarding those issues and requested a further extension of the

procedural schedule to memorialize that settlement and continue their efforts to

reach agreement on rate design issues. ALJ Fukutome granted the request by

written ruling dated January 10, 2007. In that ruling ALJ Fukutome allowed the

parties until March 16, 2007, in which to file a settlement of rate design issues.

On February 9, 2007, 22 parties filed a Settlement respecting marginal costs and

revenue allocation (February 9 Settlement). They stated that discussions would

continue in an effort to reach agreement on rate design issues.

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After several discussions, the Settling Parties to this Master Meter

Settlement reached an agreement in principle.

V. MASTER METER SETTLEMENT TERMS GENERALLY

1. The Settling Parties agree that the terms embodied in this Master Meter

Settlement are just and reasonable, in the public interest, and reflect a

reasonable compromise of Settling Parties’ proposals.

2. The Settling Parties agree that all testimony served prior to the date of

this Master Meter Settlement that addresses the issues resolved by this Master

Meter Settlement should be admitted into evidence without cross-examination by

the Settling Parties.

3. The Settling Parties further agree that this Master Meter Settlement

resolves all commercial building master meter issues in A.06-03-005, except as

otherwise expressly set forth.

VI. MASTER METER SETTLEMENT TERMS

1. PG&E and BOMA agree that it is in the public interest that commercial

building tenants receive price signals and have the opportunity to participate in

dynamic pricing and energy conservation programs.

2. PG&E and BOMA agree that it is in the public interest that building

owners participate in dynamic pricing and energy conservation programs, and

BOMA will encourage its membership to do so, and to timely pass on to

commercial tenants dynamic pricing and energy conservation options or

incentives that may become available.

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3. PG&E and BOMA agree that they may participate in any Commission

proceedings that address how dynamic pricing and energy conservation

programs may be made available to commercial building tenants. This Master

Meter Settlement does not restrict parties from taking positions they deem

appropriate in any proceeding that addresses such issues.

4. PG&E and BOMA agree that the revisions to the applicable sections of

PG&E Electric Rules 1 and 18, attached to this Master Meter Settlement as

Exhibits A and B, advance the goals set forth above and should be adopted.

5. The parties do not intend this Master Meter Settlement to be

precedential regarding any principle or issue in this proceeding or in any future

proceeding and they represent that it shall have no application to PG&E

customers other than commercial building owners, as defined in PG&E Electric

Rule 1, and shall be applicable only to commercial tenants of such building

owners.

6. Nothing in this Master Meter Settlement is intended to create or

constitute evidence of a wholesale relationship between PG&E and commercial

building owners. The parties represent that the relationship between PG&E and

commercial building owners is and will remain a retail relationship, and that

nothing in this Master Meter Settlement creates or is evidence of a commercial

relationship between PG&E and sub-metered tenants in commercial buildings.

7. Nothing in this Master Meter Settlement is intended to create or

constitute evidence of a utility relationship between commercial building owners

and their sub-metered tenants, and the parties represent and understand that

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A.06-03-005 ALJ/DKF/hkr/sid commercial building owners who sub-meter tenants do not and will not thereby

become utilities.

8. PG&E and BOMA understand and represent that the issuance of

energy statements by commercial building owners to their sub-metered tenants

will not constitute evidence that a building owner is a utility or that the building

owner's relationship with PG&E is anything other than retail.

9. PG&E and BOMA agree that the cost of electricity allocated to

commercial building tenants will be billed at the same rate as the master meter

billed by PG&E. Nothing in this Master Meter Settlement allows the master meter

owner to "re-sell" electricity. Nothing in this Master Meter Settlement prevents

building owners from separately charging tenants for submetering and energy

information services, including the amortized cost of re-wiring, meter and data

server hardware and software costs, and ongoing meter and meter data systems

operations, maintenance, and administrative costs, according to terms jointly

agreed to by tenants and owners and specified in leases.

10. PG&E and BOMA agree that implementation of this Master Meter

Settlement will be on a single premise basis, i.e., a master meter may connect to

sub-meters in only one building.

11. PG&E and BOMA agree that all attachments and devices on the

customer's side of the master meter used for the purposes stated herein to

measure tenant electricity use for the purposes of taking advantage of dynamic

pricing and energy conservation opportunities shall conform to all safety rules,

regulations, and general orders established by the State of California and its

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A.06-03-005 ALJ/DKF/hkr/sid subdivisions and local governments and their subdivisions. PG&E and BOMA

agree that all sub-meters installed by a commercial building owner will be

selected, installed and tested in accordance with Title 4 of the California Code of

Regulations. PG&E shall have no liability with respect to equipment installed on

the customer’s side of the meter pursuant to this Master Meter Settlement.

VII. SETTLEMENT EXECUTION

This document may be executed in counterparts, each of which shall be

deemed an original, but all of which together shall constitute one and the same

instrument. This Master Meter Settlement shall become effective among the

Settling Parties on the date the last Settling Party executes the Master Meter

Settlement, as indicated below. In witness whereof, intending to be legally

bound, the Settling Parties hereto have duly executed this Master Meter

Settlement on behalf of the Settling Parties they represent.

The undersigned represent that they are authorized to sign on behalf of

the Party represented.

Building Owners and Managers Association

By:______________________________

Title:_____________________________

Date:

Pacific Gas and Electric Company

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By:______________________________

Title:_____________________________

Date:

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