Corona City Council
November 20, 2024

CITY OF CORONA UTILITIES DEPARTMENT

ELECTRIC RULES & REGULATIONS
39 Effective Date: November 20, 2024
Rule 13
Temporary Service
A. Establishment of Temporary Service.

Utility shall, if no undue hardship to its existing Customers will result therefrom, furnish Temporary Service under the following conditions:

1. The Applicant shall pay, in advance or otherwise as required by Utility, the estimated cost installed, plus the estimated cost of removal, less the estimated salvage, of the facilities necessary for furnishing service.

2. The Applicant shall establish credit as required by Rule 6, except that the amount of deposit prescribed in Rule 7 shall not exceed the estimated bill for the duration of service.

B. Applicant Design.

Applicant shall design that portion of the temporary facilities in accordance with the same Applicant design provisions outlined in Rule 15.

C. Change to Permanent Status.

1. A Customer will retain temporary status as long as the Utility deems the facilities to be speculative in character, of questionable permanency, or where it is known in advance that service will be of limited duration.

2. If at any time the character of a temporary Customer’s operations changes so that in the opinion of the Utility the Customer may be classified as permanent, the Customer shall be required to take permanent service.

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ELECTRIC RULES & REGULATIONS
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Rule 14
Variations in the Quality or Supply of Electricity
A. Quality.

The Utility does not give any warranty, expressed or implied, as to the quality, adequacy, safety, or other characteristics of the electricity and/or electric service provided by the Utility.

B. Shortages, Brownouts, Interruptions, Spikes, Surges.

1. The Utility will exercise reasonable diligence (1) to furnish a continuous and sufficient supply of electricity to its Customers and (2) to minimize the occurrence of shortages, brownouts, interruptions, spikes, surges, or other electricity delivery problems; however, the Utility cannot and does not guarantee a continuous or sufficient supply, or freedom from such conditions which may affect the quality of the electricity provided.

2. The Utility will not be liable for variations in the quality of electricity supplied, nor for failure to supply a continuous or sufficient supply of electricity, nor will it be liable for variations in the quality of electricity supplied, nor for damage orloss occasioned by such failure to supply, or by shortages, brownouts,interruptions, spikes, surges, or other electricity delivery problems.

3. Whenever, in the operation of the Utility’s electric plants, properties, and/or systems, interruption in the delivery of electricity to Customers results from or is occasioned by causes other than the exercise by the Utility of its right to suspend temporarily the delivery of electricity for the purpose of making repairs or improvements to its system, notice of any such interruption will not be given to the Customers of the Utility, but the Utility will exercise reasonable diligence to reinstate delivery of electricity.

C. Temporary Suspension for Repairs.

1. The Utility, whenever it shall find it necessary for the purpose of making repairs or improvements to its system, shall have the right to suspend temporarily the delivery of electricity. In all cases, to the extent circumstances so allow, reasonable notice will be given to the Customer. Such repairs or improvements will be made as rapidly as practicable, consistent with prudent utility practices.To the extent practicable and consistent with prudent utility practices, the Utility will minimize the inconvenience to its Customers.

2. When it is necessary to suspend temporarily the delivery of electricity for repairs or improvements to the system in accordance with Rule 14, Section C.1 above, and the Customer requests that such suspension of service occur at other than during normal Utility working hours, the Utility reserves the right to receive, in advance, the total estimated labor-related costs to be incurred by the Utility for performing

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the work during non-regular Utility work hours. The Customer shall also pay any additional cost actually incurred in excess of the estimated costs.

D. Apportionment of Supply During Time of Shortage.

Should a shortage of supply ever occur, the Utility will apportion its available supply of electricity among its Customers as authorized or directed by the Utility in the manner determined at the Director of Utilities’ discretion, to be equitable under prevailing conditions. The decision of the Director of Utilities shall be final in such matters.

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ELECTRIC RULES & REGULATIONS
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Rule 15
Line Extensions
APPLICABILITY: This rule is applicable to extension of electric Distribution Lines of the Utility’s standard voltages (less than 34 kV) necessary to furnish permanent electric service to Applicants and will be made in accordance with the following provisions:

A. General.

1. Distribution Line Extension Basis.
a. Design. The Applicant will be responsible for planning, designing, and engineering Distribution Line Extensions using the Utility’s standards for material, design, and construction.
b. Ownership. The Distribution Line Extension facilities installed under the provisions of this rule, shall be owned, operated, and maintained by the Utility, except for Substructures and enclosures that are on, under, within, or part of a building or structure.
c. Private Lines. The Utility shall not be required to serve any Applicant from Distribution Line Extension facilities that are not owned, operated, and maintained by the Utility.

2. Distribution Line Extension Locations.
a. The Utility will own, operate and maintain Distribution Line Extension facilities only:
(1) Along public streets, alleys, roads, highways and other publicly dedicated ways and places which the Utility has the legal right to occupy; and
(2) On public lands and private property across which rights-of-way and permits satisfactory to the Utility may be obtained without costto or condemnation by the Utility.
b. Normal Route of Line. The length and normal route of a Distribution Line Extension will be determined by the Utility and considered as the distance along the shortest, most practical, available, and acceptable route which is clear of obstructions from the Utility’s nearest permanent and available distribution facility to the point from which the service facilities will be connected.

3. Underground Distribution Line Extensions.
a. Underground Required. The Utility, by authority of the City Council, has declared itself an “underground” utility. Consistent with this declaration,

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underground Distribution Line Extensions shall be installed where required to comply with applicable laws and ordinances of the City of Corona and where the Utility maintains or desires to maintain underground distribution facilities. For example, underground Distribution Line Extensions are required for all new: (1) Residential Subdivisions, (2) Residential Developments, (3) Commercial Developments, (4) Industrial Developments, and (5) locations that are in proximity to and visible from designated Scenic Areas. The requirements to underground lines set forth in this paragraph shall not apply where it is impractical to build underground lines, as determined by the Utility, and approved by the Director of Utilities. b. Underground Optional. When requested by Applicant and agreed upon by the Utility, underground Distribution Line Extensions may be installed in areas where it is not required, as provided in Section A.3.a.

4. Overhead Distribution Line Extensions. Overhead Distribution Line Extensions may be installed only where underground extensions are not required as provided in Section A.3.a.

5. Temporary Service. Facilities installed for Temporary Service or for operations of speculative character or questionable permanency shall be made in accordance with the fundamental installation and ownership provisions of this rule and the provisions of Rule 13.

6. Services. Service facilities connected to the Distribution Lines to serve an Applicant’s premises will be installed, owned and maintained as provided in Rule

16. 7. Street Lights. Street lights and appurtenant facilities shall be installed in accordance with the service provisions of the applicable street light schedule.

8. Contracts. Each Applicant requesting a Distribution Line Extension may be required to execute a written contract(s), prior to performing any work on the Distribution Line Extension.

B. Installation Responsibilities.

1. Underground Distribution Line Extensions.
a. In accordance with the Utility approved design, specifications, and requirements, using Qualified Contractor’s (see Section E, Applicant Installation.) Applicant is responsible for:
(1) Excavation. All necessary Trenching, backfilling, and other digging as required;
(2) Substructure and Conduits. Furnishing, installing, and upon

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acceptance by the Utility, conveying to the Utility ownership of all necessary installed Substructures and Conduits, including Feeder Conduits and related Substructures required to extend to and within subdivisions and developments; and
(3) Protective Structures. Furnishing, installing, and upon acceptance by the Utility, conveying to the Utility ownership of all necessary Protective Structures.
(4) Furnishing and installing cables, switches, transformers, and other distribution facilities required to complete the Distribution Line Extension.
b. Utility Responsibility. Providing plan check review and approval and inspection service to verify Applicant’s performance.

2. Overhead Distribution Line Extensions. The Applicant is responsible for furnishing and installing all facilities required for the Distribution Pole LineExtension.

C. Contributions or Advances by Applicant.

1. General. Contributions or Advances by an Applicant to the Utility for the installation of a Distribution Line Extension to receive Utility service consists of such things as cash payments, the value of facilities deeded to the Utility, and the value of Excavation performed by Applicant.

2. Project-Specific Cost Estimates. The Applicant’s total estimated installed cost will be based on a project-specific estimated cost.

3. Cash Advance. A cash Advance will be required for all plan check and inspection fees to complete a Distribution Line Extension.

4. Applicant shall contribute or Advance, before the start of the Applicant’s construction, the following:
a. Underground Amount. The Utility’s total estimated Applicant installed cost, to complete the underground Distribution Line Extension (including transformers, and including Betterments) for:
(1) Cabling. The Utility’s estimated value of any necessary Cabling (including distribution transformers, switches and other distribution facilities) installed by the Utility to complete the underground Distribution Line Extension. This includes the cost ofconversion of existing single-phase lines to three-phase lines, if required; plus (2) Substructures. The Utility’s estimated value of Substructures installed by Applicant and deeded to the Utility as required.

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b. Overhead Amount. The Utility’s total estimated Applicant installed cost, to complete the overhead Distribution Line Extension (including distribution transformers and excluding Betterments) for:
(1) Pole Line. All necessary facilities required for an overhead Distribution Pole Line Extension and, if required, the conversion of existing single-phase lines to three-phase lines; plus c. Other Amounts. The Utility’s estimated value of Excavation, Conduits, and Protective Structures required by the Applicant for the Distribution Line Extension under Section B.1.a.

5. Joint Applicants. The total Contribution or Advance from a group of Applicants will be apportioned among the members of the group in such manner as they may mutually agree.

D. Applicant Design for New Installations.

The Distribution Line Extension shall be designed by Applicant’s qualified contractor or sub-contractor in accordance with the Utility approved design and construction standards.

All Applicant design work of electric facilities must be performed by or under the direction of a licensed professional engineer and all design work submitted to the Utility must be certified by an appropriately licensed professional engineer, consistent with the applicable federal, state, and local, including City of Corona, codes and ordinances. The Applicant design applies to Applicant for new service and is available for replacement, reinforcement, or relocation of existing systems. Under this installation, the following applies:

1. Applicant shall notify the Utility, in a manner acceptable to the Utility.

2. Applicant designs shall conform to all applicable federal, state and local, including City of Corona, codes and ordinances for Utility installations design (such as, but not limited to the California Business and Professions Code).

3. The Utility may require Applicant designers to meet the Utility’s prequalification requirements prior to participating in Applicant design.

4. Applicant designers shall obtain Utility design and construction standards and specifications prior to performing Applicant design. The Utility may charge for any of these services.

5. The Utility will perform plan check on each Applicant design project at the expense to Applicant.

6. The Utility shall perform all the Utility’s project accounting and cost estimating.

E. Applicant Installation.

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1. The Distribution Line Extension shall be installed by Applicant’s qualified contractor or sub-contractor in accordance with the Utility approved design and specifications. All Applicant installation work for electric facilities must be performed by a qualified Contractor and approved by the Utility consistent with the applicable federal, state, and local, including City of Corona, codes andordinances.

Under this installation, the following applies:
a. The Utility’s total estimated Applicant installed project cost will apply regardless of whom Applicant selects to perform the installation. b. Upon acceptance by the Utility, ownership of all such facilities will transfer to the Utility.
c. Applicant shall pay to the Utility any Utility costs associated with the Distribution Line Extension, including the estimated costs of design, administration, and installation of any additional facilities and labor necessary to complete the Distribution Line Extension.
d. Applicant shall pay to the Utility the cost of inspection. f. Only duly authorized employees of the Utility are allowed to connect to, disconnect from, or perform any work upon the Utility’s facilities.

2. Minimum Contractor Qualifications. Applicant’s contractor or subcontractor (QC/S) shall:
a. Be licensed in California for the appropriate type of work (electrical and general, etc.).
b. Employ workmen properly qualified for specific skills required (Qualified Electrical Worker, Qualified Person, etc.) as defined in State of California High Voltage Safety Orders (Title 8, Chapter 4, Subchapter 5, Group 2). c. Comply with applicable laws(Equal Opportunity Regulations, OSHA,EPA, etc.).

3. Other Contractor Qualifications. An Applicant for service who intends to employ a QC/S also should consider whether the QC/S:
a. Is technically competent.
b. Has access to proper equipment.
c. Demonstrates financial responsibility commensurate with the scope of the contract.
d. Has adequate insurance coverage (worker’s compensation, liability, property damage, etc.).

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e. Is able to furnish a surety bond for performance of the contract, if required.

F. Special Conditions.

1. Facility Relocation or Rearrangement. Any relocation or rearrangement of the Utility’s existing facilities, at the request of, or to meet the convenience of an Applicant or Customer, and agreed upon by the Utility, shall be performed by the Applicant. Where new facilities can be constructed in a separate location, before abandonment or removal of any existing facilities, and Applicant requests to perform the new construction work, it can be performed under the applicable provisions of Section E, Applicant Installation.

In all instances, the Utility shall abandon or remove its existing facilities at the option of the Utility. Applicant or Customer shall be responsible for the costs of all related relocation, rearrangement and removal work.

I. Definitions for Rule 15.

Advance: Cash payment made to the Utility prior to the initiation of any work done by the Utility.

Applicant: A person or agency requesting the Utility to deliver/supply electric service.

Betterment: Facilities installed by Applicant at the request of the Utility in addition to those required under Section B.1.a.

Cabling: Conductors (including cable-in-conduit, if used), connectors, switches, as required by the Utility for primary, secondary, and service installations.

Commercial Development: Two (2) or more enterprises engaged in trade or the furnishing of services, (e.g., shopping centers, sales enterprises, business offices, professional offices, and educational or governmental complexes) located on a single parcel or on two (2) or more contiguous parcels of land.

Conduit: Ducts, pipes or tubes of certain metals, plastics and other materials acceptable to the Utility (including pull wires and concrete encasement where required) for the installation and protection of electric wires or cables.

Contribution: In-kind services and the value of all property conveyed to the Utility at any time during the Utility’s work on an extension which is part of the Utility’s total estimated installed cost of its facilities, or cash payments.

Distribution Line Extension: A new distribution facility of the Utility that is a continuation of, or branches from, the nearest available existing permanent Distribution Line (including any facility rearrangements and relocations necessary to accommodate the Distribution Line Extension) to the point of connection of the last service. The Utility’s Distribution Line Extension includes transmission under builds and converting an existing

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single-phase line to three-phase in order to furnish three-phase service to an Applicant, but excludes service transformers, Meters and services.

Distribution Lines: Overhead and underground facilities which are operated at distribution voltages, and which are designed to supply two (2) or more services.

Excavation: All necessary Trenching, backfilling, and other digging to install Distribution Line Extension facilities, including furnishing of any imported backfill material and disposal of spoil as required, surface repair and replacement, landscaperepair and replacement.

Feeder Conduit: Conduit for such uses as part of a backbone system to provide for future anticipated load growth outside the subdivision involved, to provide for future anticipated load growth in the existing subdivision and the existing subdivisions in close proximity, to balance loads between substations, to interconnect the service to the subdivision with service to subsequent developments outside the subdivision, and to provide the flexibility and versatility of modifying or supplying emergency backup powerto the area involved.

Industrial Development: Two (2) or more enterprises engaged in a process which creates a product or changes material into another form or product and located on a singleparcel or on two (2) or more contiguous parcels of land.

Pole Line: Poles, cross-arms, insulators, conductors, switches, guy-wires, and other related equipment used in the construction of an electric overhead line.

Protective Structures: Fences, retaining walls (in lieu of grading), sound barriers, posts, or barricades and other structures as required by the Utility to protect distribution equipment.

Residential Development: Five (5) or more dwelling units in two (2) or more buildings located on a single parcel of land.

Residential Subdivision: An area of five (5) or more lots for residential dwelling units which may be identified by filed subdivision plans or an area in which a group of dwellings may be constructed about the same time, either by a builder or several builders working on a coordinated basis.

Seasonal Service: Electric service to establishments which are occupied seasonally or intermittently, such as seasonal resorts, cottages, or other part-time establishments.

Scenic Areas: An area such as a scenic highway, a state or national park or other area determined by a governmental agency to be of unusual scenic interest to the general public.

Scenic highways are officially designated under the California Scenic Highway Program established pursuant to Paragraph 320 of the Public Utilities Code. State or national parks or other areas of unusual scenic interest to the general public are determined by the appropriate governmental agency. “In proximity to” shall mean within1,000 feet from each edge of the right-of-way of designated scenic highways and fromthe boundaries of designated parks and scenic areas. “Visible from” shall mean that overhead distribution

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facilities could be seen by motorists or pedestrians traveling along scenic highways or visiting parks or scenic areas.

Substructures: The surface and subsurface structures which are necessary to contain or support the Utility’s electric facilities. This includes, but is not limited to, such things as splice boxes, Pull Boxes, equipment vaults and enclosures, foundations or pads forsurfacemounted equipment.

Trenching: See Excavation.

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Rule 16
Electric Service
APPLICABILITY: This rule is applicable to both (1) Utility Service Facilities1that extend from the Utility’s Distribution Line facilities to the Service Delivery Point, and (2) service related equipment required of Applicant on Applicant’s Premises to receive electric service.

A. General.

1. Design. The Applicant will be responsible for planning, designing, and engineering Service Extensions using the Utility approved standards for design, materials and construction in accordance with the Applicant design provisions of Rule 15.

2. Service Facilities. The Utility’s Service Facilities shall consist of (a) primary or secondary underground or overhead service conductors, (b) poles to support overhead service conductors, (c) service transformers, (d) Utility-owned Metering equipment, and (e) other Utility-owned service related equipment.

3. Ownership of Facilities. Service Facilities installed under the provisions of this rule shall be owned, operated, and maintained by the Utility if they are (a) located in the street, road or a public right-of-way area, (b) installed by the Applicant under section D.2 below on Applicant’s Premises for the purpose of the deliveryof electric energy to Applicant, or (c) installed by Applicant under the provisions of this rule, and conveyed to the Utility.

4. Private Lines. The Utility shall not be required to connect Service Facilities to or serve any Applicant from electric facilities that are not owned, operated, and maintained by the Utility.

5. Temporary Service Facilities. Service Facilities installed for Temporary Service or for operations of speculative character or questionable permanency shall be made in accordance with the fundamental installation and ownership provisions ofthis rule, except that all charges and refunds shall be made under the provisions ofRule

13. 6. Street Lights. Street light services and appurtenant facilities shall be installed in accordance with the service provisions of the applicable street light schedule. 1 Certain words beginning with capital letters are defined either within the provisions of this rule or in Section H.

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7. Contracts. Each Applicant requesting service may be required to execute awritten contract(s) prior to the Applicant performing its work to establish service. Such contract(s) shall be in the form provided by the Utility or otherwise acceptable and approved by the Utility.

8. Distribution Line Extension. Whenever the Utility’s Distribution System is not complete to the point designated by the Utility where the Service Extension is to be connected to the Utility’s Distribution System, the extension of Distribution Line facilities will be installed by the Applicant in accordance with Rule 15.

9. Rights-of-Way. Rights-of-way or easements may be required by the Service Facilities on Applicant’s property to serve only Applicant. a. Service Facilities. If the Service Facilities must cross property owned by a third party to serve Applicant, the Utility may, at its option, install such Service Facilities after appropriate rights-of-way or easements, satisfactory to the Utility, are obtained without cost to the Utility; or b. Distribution Line Extensions. If the Utility’s facilities installed on Applicant’s property, or third-party property, will be or are designed to serve adjacent property, then the Utility may, at its option, install itsfacilities under Rule 15, after appropriate rights-of-way or easements,satisfactory to the Utility, are obtained without cost to the Utility.
c. Clearances. Any necessary rights-of-way or easements for the Utility’s facilities shall have provisions to maintain legal clearances from adjacent structures.
d. The Customer shall exercise reasonable care to prevent the facilities of the Utility upon the premises from being damaged or destroyed, and shall not relocate or otherwise interfere with them and if, any defect is discovered, shall promptly notify the Utility.

10. Access to Applicant’s Premises. The Utility shall, at all times, have the right to enter and leave Applicant’s Premises for any purpose connected with the furnishing of electric service (Meter reading, inspection, testing, routine repairs, replacement, maintenance, emergency work, etc.) and the exercise of any and all rights secured to it by law, or under the Utility’s Tariff Schedules. These rights include, but are not limited to:
a. The use of a Utility-approved locking device, if Applicant desires toprevent unauthorized access to the Utility’s facilities;
b. Safe and ready access for Utility personnel free from unrestrained animals; c. Unobstructed ready access for the Utility’s vehicles and equipment to install, remove, repair, or maintain its facilities;

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d. Removal of any and all of its property installed on Applicant’s Premises after the termination of service.

11. Service Connections. Only personnel duly authorized by the Utility are allowed to connect or disconnect service conductors to or from the Utility’s Distribution Lines, remove Meters unless otherwise allowed pursuant to Utility Tariff Schedules, remove Utility-owned Service Facilities, or perform any work upon Utility-owned existing facilities.

12. Due to the long lead time for engineering, material acquisition, crew scheduling and construction, application for service must be made as far in advance aspossible.

After receipt of fees, service charges and deposits and clearance from the inspection agency having jurisdiction, the Utility shall endeavor to complete within a reasonable time the inspection and approval of the necessary facilities installed by the Applicant. However, the Utility shall not be liable for any delays encountered in completing the installed facilities.

13. If, for any reason of the Applicant, installation of a service cannot be accomplished during standard working hours, the Applicant shall pay in advance the estimated cost of the Utility overtime, to the extent that it exceeds any costs included in other Applicant charges.

14. The Applicant shall be obligated to provide facilities adequate to serve only the load initially specified and connected, regardless of the rating of the service equipment, service switch or breaker. Increased loads will be considered as new installations and the Customer shall pay the net cost of any changes required in the Utility facilities in accordance with and may be required to make specified changes in the services facilities or equipment to accommodate the increased load or the type of service to be supplied by the Utility.

B. Metering Facilities.

1. General.
a. Meter All Usage. Delivery of all electric power and energy will bemetered, unless otherwise provided for by the Utility’s Tariff Schedules orby other applicable laws.
b. Meter Location. All Meters and associated metering equipment shall be located at some protected location on Applicant’s Premises as approved by the Utility.

2. Number of Meters. Normally only one Meter will be installed for a single-family residence or a single non-residential enterprise on a single Premises, except:
a. When otherwise required or allowed under the Utility’s Tariff Schedules.

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b. At the option of and as determined by the Utility, for its operating convenience, consistent with its engineering design; or c. When required by law or local ordinance;
d. When additional services are granted by the Utility.

A single Meter is required for each single enterprise operating in one building or group of buildings or other development on a single Premises such as, but not limited to, a commercial business, school campus, industrial manufacturer, or recreational vehicle park, unless otherwise approved by the Utility.

3. Multiple Occupancy. In a building with two or more tenants, or where more than one Meter is furnished on the same Premises, the Meters normally shall begrouped at one central location, or as otherwise specified by the Utility, and each Meter position or socket shall be clearly and permanently marked by Applicant, Customer, or owner of the Premises to indicate the particular unit, occupancy, or load supplied by it.
a. Residential. For revenue billing, electric service shall be individually metered to every Residential Unit in a residential building or group of buildings or other development with multiple tenants such as, but not limited to, apartment buildings, mobile home parks, etc., except as may be specified in Rule 18 and applicable Rate Schedules.
b. Non-residential. For revenue billing, electric service shall be individually metered to each tenant in a non-residential building or group of buildings or other development on a single Premises with multiple tenants or enterprises (such as, but not limited to, an office building or shopping center complex).

Alternative metering arrangements as determined by the Utility may be allowed only as specified in Rule 18 and applicable Rate Schedules.

C. Service Extensions.

1. General Location. The location of the Service Extension shall extend:
a. Public Right-of-way Area: From the point of connection at the Distribution Line to Applicant’s nearest property line abutting upon any street, highway, road, or right-of-way, along which it already has, or willinstall distribution facilities; and
b. Private Party: On private property, along the shortest, most practical and available route (clear of obstructions) as necessary to reach a Service Delivery Point designated by the Utility.

2. Number of Service Extensions. The Utility will not normally provide more than one Service Extension, including associated facilities, either overhead or underground for any one building or group of buildings, for a single enterprise on

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a single Premises, except:
a. Tariff Schedules. Where otherwise allowed or required under the Utility’s Tariff Schedules; or
b. Utility Convenience. At the option of and as determined by the Utility, for its operating convenience, consistent with its engineering design for different voltage and phase classification, or when replacing an existing service; or
c. Ordinance. Where required by City of Corona ordinance or other applicable law, for such things as fire pumps, fire alarm systems, etc. d. Other. The Utility may charge for additional services provided under this paragraph, as Special or Added Facilities.

3. Underground Installations. Underground Service Extensions will be installed:
a. Underground Required. Underground Service Extensions (1) shall be installed where required to comply with applicable Tariff Schedules, laws, City of Corona ordinances, or similar requirements of governmental authorities having jurisdiction, and (2) may be necessary as determined by the Utility where Applicant’s load requires a separate transformer installation of 300 kVa or greater.
b. Underground Optional. An underground Service Extension may be installed in an area where it is not otherwise required and when requested by Applicant and agreed upon by the Utility.

4. Overhead Installations. Overhead Service Extensions are permitted except under the circumstances specified in Section C.3.a above.

5. Unusual Site Conditions. In cases where Applicant’s building is located a considerable distance from the available Distribution Line or where there is an obstruction or other deterrent obstacle or hazard such as plowed land, ditches, or inaccessible security areas between the Utility’s Distribution Line and Applicant’s building or facility to be served that would prevent the Utility from prudently installing, owning, and maintaining its Service Facilities, the Utility may at its discretion, waive the normal Service Delivery Point location. In such cases, the Service Delivery Point will be at such other location on Applicant’s property as may be mutually agreed upon; or, alternatively, the Service Delivery Point may be located at or near Applicant’s property line as close as practical to the available Distribution Line.

D. Responsibilities for New Service Extensions.

1. Applicant Responsibility. In accordance with the Utility’s design, specifications, and requirements for the installation of Service Extensions, subject to the Utility’s

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inspection and approval, Applicant is responsible for:
a. Service Extensions.
(1) Clear Route. Providing (or paying for) a route on any private property that is clear of obstructions which would inhibit the construction of either underground or overhead Service Extensions. (2) Excavation. All necessary Trenching, backfilling, and other digging as required including permit fees.
(3) Conduit and Substructures.
(a) Furnishing, installing, owning, and maintaining all Conduits (including pull ropes) and Substructures on Applicant’s Premises.
(b) Installing (or paying for) any Conduits and Substructures in Utility’s Franchise Area (or rights-of-way, if applicable) as necessary to install the Service Extension.
(c) Conveying ownership to the Utility upon its acceptance of those Conduits and Substructures not on Applicant’s
Premises.
(4) Protective Structures. Furnishing, installing, owning, and maintaining all necessary Protective Structures as specified by the Utility for Utility’s facilities on Applicant’s Premises. (5) Furnishing and installing all cables, transformers, electrical apparatus and terminating all required components to provide a complete, safe and reliable electrical service extension. b. Applicant’s Facility Design and Operation. Applicant shall be solely responsible to plan, design, install, own, maintain, and operate facilities and equipment beyond the Service Delivery Point (except for Utility-owned metering facilities) in order to properly receive and utilize the type of electric service available from the Utility. Refer to Rule 2 for a description, among other things, of:
(1) Available service delivery voltages and the technical requirements and conditions to qualify for them;
(2) Customer utilization voltages;
(3) Load balancing requirements;
(4) Requirements for installing electrical protective devices;

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(5) Loads that may cause service interference to others; and (6) Motor starting limitations.
c. Required Service Equipment. Applicant shall, at its sole liability, risk, and expense, be responsible to furnish, install, own, maintain, inspect, and keep in good and safe condition, all facilities of any kind or character on Applicant’s Premises that are not the responsibility of the Utility but are required by the Utility for Applicant to receive service. Such facilities shall include but are not limited to the overhead or underground termination equipment, Conduits, service entrance conductors from the Service Delivery Point to the location of the Utility’s metering facilities, connectors, Meter sockets, Meter and instrument transformer housing,service switches, circuit breakers, fuses, relays, wire ways, metered conductors, machinery and apparatus of any kind or character. Detailed information on the Utility’s service equipment requirements will be furnished by the Utility. d. Coordination of Electrical Protective Devices. When, as determined by the Utility, Applicant’s load is of sufficient size as to require coordination of response time characteristics between Applicant’s electrical protective devices (circuit breakers, fuses, relays, etc.) and those of the Utility, it shall be Applicant’s responsibility to provide such coordination in accordance with Rule 2.
e. Liability. The Utility shall incur no liability whatsoever, for any damage, loss or injury occasioned by:
(1) Applicant-owned equipment or Applicant’s transmission and delivery of energy; or
(2) The negligence, omission of proper protective devices, want of proper care, or wrongful act of Applicant, or any agents,employees, or licensees of Applicant, on the part of Applicant in installing, maintaining, using, operating, or interfering with any such conductors, lines, machinery, or apparatus.
f. Facility Tampering. Applicant shall provide a suitable means acceptable to the Utility for placing its seals on Meter rings and covers of service enclosures and instrument transformer enclosures which protect unmetered energized conductors installed by Applicant. All Utility-owned Meters and enclosure covers will be sealed only by the Utility’s authorized employees and such seals shall be broken only by the Utility’s authorized employees. However, in an emergency, the Utility may allow a public authority or other appropriate party to break the seal. Any unauthorized tampering with Utility-owned seals or connection of Applicant-owned facilities to unmetered conductors at any time is prohibited and is subject

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to the provisions of Rule 11 for Unauthorized Use.
g. Transformer Installations on Applicant’s Premises. Transformer installations on Applicant’s Premises shall be as specified by the Utility and in accordance with the following applicable provisions:
(1) Space for Transformers. Applicant shall provide space on Applicant’s Premises at a location approved by the Utility for a standard transformer installation including any necessary switches, capacitors, and electric protective equipment where required if (a) in an overhead area, the Utility determines that the load to be served is such that a separate transformer installation, or (b) if the Utility determines that the installation of a pad mounted or subsurface transformer of any size is required on Applicant’s Premises to serve only Applicant.
(2) Pad Mounted Equipment. In the Applicant’s standard installation, Applicant shall furnish, install, own, and maintain, at its expense, Substructures and any required Protective Structures as specified by the Utility for the proper installation of the transformer, switches, capacitors, etc., as determined by the Utility.
(3) Single Utility-Owned Customer Substation. When the Utility elects for its operating convenience to supply Applicant from a transmission line and install a Utility-owned substation on Applicant’s Premises, Applicant shall furnish, install, own and maintain at its expense the necessary site improvements as specified by the Utility for the proper installation of the transformer. Such improvements shall include but are not limited to a concrete pad or foundation, grounding system, fences and gates, access road, grading, and paving as required, etc. Detailed information on the Utility’s requirements for a single Customer substation will be furnished by the Utility.
(4) Transformer Room or Vault. Where Applicant requests and the Utility approves the installation of the transformer(s) in a vault or room on Applicant’s Premises, rather than the Utility’s standard pad mounted installation:
(a) The room or vault on Applicant’s Premises shall be
furnished, installed, owned, and maintained by Applicant and shall meet the Utility’s specifications for such things as access, ventilation, drainage, grounding system, etc.
(b) If space cannot be provided on Applicant’s Premises for the installation of a transformer on either a pad or in a room or vault, a vault will be installed at Applicant’s expense in the

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street near the property line. It shall be Applicant’s
responsibility to install (or pay for) such vault if not restricted by governmental authority having jurisdiction,and Applicant shall convey ownership of the vault to the Utility upon its acceptance. The additional facilities shall be treated as Special or Added Facilities under theprovisions of Rule

2. (c) If the Applicant’s installed cost for the transformer in the room or vault is more costly than the standard pad mounted transformer installation, the additional costs shall be paid by Applicant.
(5) Transformer Lifting Requirements. Where the Applicant has installed or agrees to install, transformers at locations where the Applicant cannot use its standard transformer lifting equipment and special lifting facilities are required to install or remove the transformers on Applicant’s Premises, Applicant shall, at its expense, (a) furnish, install, own, and maintain permanent lifting facilities and be responsible for lifting the transformer to and from its permanent position, or (b) provide (or pay for) portable lifting facilities acceptable to the Utility for installing or removing the transformers. Rights-of-way and space provisions shall be provided by Applicant such that access and required clearances from adjacent structures can be maintained.
(6) Overhead Transformers. In remote areas or in areas not zoned for residential or commercial use or for underground services, pad mounted transformers are preferred for installation on Applicant’s Premises; however, where the Utility determines that it is not practical to install a transformer on a pad, in a room or vault, the Applicant may furnish a pole-type structure for an installation not exceeding 500 kVA.
h. Building Code Requirements. Any service equipment and other related equipment owned by Applicant, as well as any vault, room, enclosure, or lifting facilities for the installation of transformers shall conform with applicable laws, codes, and ordinances of all governmental authorities having jurisdiction.
i. Reasonable Care. Applicant shall exercise reasonable care to prevent the Utility’s Service Extension, other Utility facilities, and Meters owned by the Utility or others on the Applicant’s Premises from being damaged or destroyed, and shall refrain from interfering with the Utility’s operation of the facilities and shall notify the Utility of any obvious defect. Applicant may be required to provide and install suitable mechanical protection (barrier posts, etc.) as required by the Utility.

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2. Utility Responsibility.
a. Service, Meter and Transformers. The Utility will operate, own, and maintain the following Service Facilities as applicable after Applicantmeets all requirements to receive service:
(1) Underground Service. A set of service conductors to supply Permanent Service from the Distribution Line source to the Service Delivery Point approved by the Utility.
(2) Riser Materials. Any necessary pole riser material for connecting underground services to an overhead Distribution Line.
(3) Overhead Service. A set of overhead service conductors and support poles to supply permanent service from a Distribution Linesource to a suitable support at the Service Delivery Point approved by the Utility. Such support shall be of a type and located such that service wires may be installed in accordance with good engineering practice and in compliance with all applicable laws, ordinances, rules, and regulations including those governing clearances and points of attachment.
(4) Metering. When the Meter is owned by the Utility, the Utility will be responsible for the necessary instrument transformers where required, test facilities, Meters, associated metering equipment,and the metering enclosures when the Utility elects to locate metering equipment at a point that is not accessible to Applicant. (5) Transformer. The transformer where required, including any necessary switches, capacitors, electrical protective equipment, etc.

When either a pad mounted or overhead transformer is installed on Applicant’s Premises, the Service Extension shall include the primary conductors from the connection point at the distribution supply line to the transformer and the secondary conductors, if any, from the transformer to the Service Delivery Point.
b. Special Conduit Installations. The Utility shall own and maintain service Conduits only if: (1) they are located in the same trench with distribution facilities, and (2) when it is necessary to locate Conduits on property other than that owned by Applicant, as determined by the Utility, or as may be required by local authorities.
c. Government Inspection. The Utility will establish electric service to Applicant following notice from the governmental authority having jurisdiction that the Applicant-owned facilities have been installed and inspected in accordance with any applicable laws, codes, ordinances, rules,

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or regulations, and are safe to energize.
d. Applicant-Performed Work. The Applicant shall install that portion of the new Service Extension in accordance with the same provisions outlined in Rule 15.

E. Payments by Applicant.

1. Payments. Applicant is responsible to pay the Utility the following costs as applicable under this rule and in advance of the Applicant commencing its work:
a. All Plan Check Fees.
b. All Inspection Fees.
c. All Temporary Power Fees.

F. Existing Service Facilities.

1. Service Reinforcement.
a. Utility Owned. When the Utility determines that its existing Service Facilities require replacement, the existing Service Facilities shall be replaced as a new Service Extension under the provisions of this rule. b. Applicant-Owned. When the Utility determines that existing Applicantowned Service Facilities (installed under a prior rule) require replacement, such replacement shall be accomplished under the provisions for a new Service Extension, except that if the Utility determines that any portion of Applicant’s existing service conductors can be utilized by the Utility, Applicant will convey any such usable part to the Utility.

Applicant will replace or reinforce that portion of the Service Extension which Applicant will continue to own under the provisions of this rule for new services.

2. Service Relocation or Rearrangement.
a. Utility Convenience. When, in the judgment of the Utility, the relocation or rearrangement of a service, including Utility-owned transformers, is necessary for the maintenance of adequate service or for the operating convenience of the Utility, the Utility normally will perform such work at its own expense, except as provided in Sections F.2.b. and F.5. b. Applicant Convenience. Any relocation or rearrangement of the Utility’s existing Service Facilities at the request of Applicant (aesthetics, building additions, remodeling, etc.) and agreed upon by the Utility shall be

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performed in accordance with Section D above except that Applicant shall pay the Utility its total estimated costs.

In all instances, the Utility shall abandon or remove its existing facilities, at the option of the Utility, rendered idle by the relocation or rearrangement.

3. Impaired Access and Clearances. Whenever the Utility determines that:
a. Access. Its existing Service Facilities have become inaccessible for inspecting, operating, maintenance, Meter reading, or testing; or b. Clearances. A hazardous condition exists or any of the required clearances between the existing Service Facilities and any object becomes impaired under any applicable laws, ordinances, Rules, or regulations of the Utility or other public authorities, then the following applies. c. Corrective Action. Applicant or owner shall, at Applicant’s or owner’s expense, either correct the access or clearance infractions to relocate its facilities to a new location which is acceptable to the Utility. Applicant or owner shall also be responsible for the expense to relocate any equipment which Applicant owns and maintains. Failure to comply with corrective measures within a reasonable time may result in discontinuance of service.

4. Overhead to Underground Service Conversions.
a. Where an existing overhead Distribution Line is replaced by anunderground Distribution System, new underground services will be installed under Rule

16. b. Applicant Convenience Where overhead services are replaced by underground servicesfor Applicant’s convenience, Applicant shall perform all Excavation, furnish and install all Substructures, and pay the total cost to complete the new service and remove the overhead facilities.

5. Damaged Facilities. When the Utility’s facilities are damaged by others, the repair will be made by the Utility at the expense of the party responsible for the damage.

Applicants are responsible for repairing their own facilities.

6. Subdivision of Premises. When the Utility’s Service Facilities are located on private property and such private property is subsequently subdivided into separate Premises with ownership divested to other than Applicant or Customer, the subdivider isrequired to provide the Utility with adequate rights-of-waysatisfactory to the Utility for its existing facilities and to notify property owners of the subdivided Premises of the existence of the rights-of-way.

When adequate rights-of-way are not granted as a result of the property subdivision, the Utility shall have the right, upon written notice to Applicant, to discontinue service without obligation or liability. The existing owner, Applicant,or Customer

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shall pay to the Utility the total estimated cost of any required relocation or removal of the Utility’s facilities. A new electric service will be re- established in accordance with the provisions of Section D above for new service and the provisions of any other applicable Utility Rules.

G. Definitions for Rule 16.

Applicant: A person or agency requesting the Utility to supply electric service.

Customer: The person 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 or Summary Bills regularly issued in his or her name regardless of the identity of the actual user of the service. A Customer may also be a party with whom the Utility is doing business with or without a billing relationship.

Conduit: Ducts, pipes, or tubes of certain metals, plastics or other materials acceptable to the Utility (including pull wires and concrete encasement where required) for the installation and protection of electric wires and cables.

Distribution Lines: The Utility’s overhead and underground facilities which are operated at distribution voltages as set forth in the Utility’s Rule 2 and which are designed to supply two (2) or more services.

Excavation: All necessary Trenching, backfilling, and other digging as required to install Service Extensions including furnishing of any imported backfill material, concrete encasement to protect conduit, and disposal of spoil as required, surface repair and replacement, landscape repair and replacement.

Meter: The instrument used for measuring the electricity delivered to the Customer.

Permanent Service: Service which, in the opinion of the Utility, is of a permanent andestablished character. This may be continuous, intermittent, or seasonal in nature.

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 a 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.

Protective Structures: Fences, retaining walls (in lieu of grading), sound barriers, posts, barricades and other structures as required by the Utility.

Residential Unit: A residential dwelling unit consisting of a room or group of rooms which do not qualify as single-family dwellings. Residential units may be used as permanent primary dwellings, as transient tenant accommodations, and by organizations or groups of persons.When such unit is used by a transient tenant, an organization, or a group of persons, use shall be nondomestic service.

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Service Delivery Point: Where the Utility’s Service Facilities are connected to either Applicant’s conductors or other service termination facility designated and approved by the Utility.

Service Extension: The overhead and underground primary or secondary facilities (including, but not limited to Utility-owned Service Facilities and Applicant-owned service facilities) extending from the point of connection at the Distribution Line to the Service Delivery Point. When an underground Service Extension is supplied from a Utility-designated overhead pole, thebeginning point of connection to the Utility’s Distribution Line shall be where the Service Extension is connected to the Utility’s overhead Distribution Line conductors.

Substructures: The surface and subsurface structures which are necessary to contain or support the Utility’s electric facilities. This includes but is not limited to splice boxes, Pull Boxes, equipment vaults and enclosures, foundations or pads for surface-mounted equipment.

Temporary Service: Service for enterprises or activities which are temporary in character or where it is known in advance that service will be of limited duration. Service, which in the opinion of the Utility, is for operations of a speculative character or the permanency of which hasnot been established, also is considered Temporary Service.

Trenching: See Excavation.

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Rule 17
Adjustment of Bills and Meter Tests
A. General.

Estimated Usage: When regular, accurate Meter readings are not available or the electric usage has not been accurately measured, Utility may estimate the Customer’s energy usage for billing purposes on the basis of information including, but not limited to, the physical condition of the metering equipment, available Meter readings, records of historical use, and the general characteristics of the Customer’s load and operation.

B. Meter Tests.

1. Prior to Installation. Every Meter will be tested at or prior to the time of installation, and no Meter will be placed in service if found to register more than one percent (1%) fast or one percent (1%) slow.

2. On Customer Request. A Customer may, on notice of not less than one week, require the Utility to test the Meter for the Customer’s service.

No charge will be made for such test, but should a Customer demand a test within four (4) months after installation or more often than once in six (6) months, a deposit will be required to cover the cost of the test. This deposit will be returned if the Meter is found to register more than two percent (2%) fast or two percent (2%) slow. The amount of the deposit will be dependent on the type of Meter to be tested.

A Customer shall have the right to require the Utility to conduct the test in the Customer’s presence or in the presence of an expert or other representative appointed by the Customer. The results of the test will be furnished to the Customer within a reasonable time after completion of the test.

C. Adjustment of Bills for Meter Error.

A Meter Error is incorrect kilowatt-hour, kilovar-hour, or demand registration resulting from a malfunctioning or defective Meter. It does not include Billing Error, Unauthorized Use, or an error in registration caused by Meter tampering by an unauthorized person. It also does not include conditions such as grounds, shorts, incorrect Meter readings, Meter dial-overs, improper load wiring (including other Customers’ circuits connected to the wiring), accounting errors, switched Meters, improper Customer wiring, blown fuse in one energized conductor, or incorrect Meter sizing.

Where, as the result of a Meter test, a Meter is found to be non-registering or incorrectly registering, Utility may render an adjusted bill to the Customer for the amount of the undercharge, and shall issue a refund or credit to the Customer for the amount of the overcharge, computed back to the date that Utility determines the Meter Error commenced, except that the period of adjustment shall not exceed three (3) years. Such adjusted bill

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shall be computed in accordance with the following:

1. Fast Meters. When any Meter is tested and found to be registering more than two percent (2%) fast, the Utility will refund to the Customer the amount of the overcharge, based on corrected Meter readings or Utility’s estimate of the energy usage either for the known period of Meter Error or, if the period of error is not known, for the period during which the Meter was in use, not to exceed three (3) months.

2. Slow Meters. If a Meter for residential service is found to be registering more than twenty-five percent (25%) slow, or any Meter for other class of service is found to be registering more than two percent (2%) slow, Utility may bill the Customer for the amount of the undercharge based on corrected Meter readings orUtility estimate of the energy usage either for the known period of Meter Error or,if the period of Meter Error is not known for the period the Meter was in use, not exceeding three (3) months in the case of a residential service to a Utility-meteredSingle-Family Dwelling or Accommodation as defined in Rule 1 and three (3) years for all other services.

3. Non-registering Meters. When any Meter is tested and found to be non- registering, the Utility may bill the Customer for the estimate of electricity consumed but not registered, not exceeding three (3) months in the case of residential service to a Utility-metered Single-Family Dwelling or Accommodation as defined in Rule 1 and three (3) years for all other service. Bills for this purpose will be estimated by the Utility.

D. Adjustment of Bills for Billing Error.

A Billing Error is an error by Utility which results in incorrect billing charges to the Customer. Billing Errors may include incorrect Meter reads or clerical errors by a Utility representative such as applying the wrong rate, wrong billing factor, or an incorrect calculation. Billing Error does not include a Meter Error or Unauthorized Use, nor any error in billing resulting from Meter dial over caused by other than Utility; switched or mismarked Meters by other than Utility; improper Customer wiring; blown fuse in one energized conductor; inaccessible Meter; failure of the Customer to notify Utility of changes in the Customer’s equipment or operation; or failure of the Customer to take advantage of a rate or condition of service or which the Customer is eligible.

Where Utility overcharges or undercharges a Customer as the result of a Billing Error, Utility may render an adjusted bill for the amount of the undercharge, and shall issue a refund or credit to the Customer for the amount of the overcharge for the period of the billing error, but not exceeding three (3) years in the case of an overcharge, and, in the case of an undercharge, not exceeding three (3) months for residential service to a Utility-metered Single-Family Dwelling or Accommodation as defined in Rule 1 and three (3) years for all other service. The Utility is authorized to refund a credit balance.

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E. Adjustment of Bills for Unauthorized Use.

Unauthorized Use is the use of energy in noncompliance with Utility’s tariffs or applicable law. It includes, but is not limited to Meter tampering, unauthorized connection or reconnection, theft, fraud, intentional use of energy whereby Utility is denied full compensation for electric service provided.

Where the Utility determines that there has been Unauthorized Use of electric service, Utility may bill the Customer for Utility’s estimate of such Unauthorized Use. However, such estimated bill shall indicate Unauthorized Use for the most recent three (3) years and, separately, Unauthorized Use beyond the three-year period for collection as provided by law.

Nothing in this Rule shall be interpreted as limiting Utility’s rights under any provision of any applicable law.

1. Actual Usage.

If accurate Meter readings from a remote check Meter are available for the Unauthorized Use period, they will be used for billing purposes.

2. Estimated Usage.

If the electric usage has not been accurately measured, Utility may estimate the energy usage for billing purposes. The basis for the estimate may include, without limitation, the physical condition of the Metering equipment, available Meter readings, records of historical use, or the general characteristics of the load and operation of the Customer or person being billed, with consideration of any appropriate seasonal adjustment.

Estimated bills for the Unauthorized Use period may be determined by Utility based on one or more of the following, without limitation:
a. Accurately-metered use from a remote check Meter during the Unauthorized Use period;
b. The known percent error in metering attributable to the Unauthorized Use; c. Accurately-metered use prior to the onset of the Unauthorized Use; d. The equipment and hours of operation of the Customer or person being billed;
e. Accurately-measured subsequent use of thirty (30) days or more (if available);
f. Annual use profile of at least five (5) Customers with similar Connected Load, Premises load profiles, hours or energy use, etc. (percent of annual

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use); or
g. Other reasonable and supportable billing methodology when none of the aforementioned billing techniques are appropriate under thecircumstances.

3. Recovery of Associated Costs.

Utility may recover from the Customer the associated costs resulting from the Unauthorized Use including both investigative and equipment damage costs.

Investigative costs include time and material spent for investigation, bookkeeping, film and film development, and other costs of gathering evidence. Equipment damage costs include the cost of replacing the Utility-owned equipment damaged by the Customer.

4. Discontinuance of Service.

In accordance with the provisions of Rule 11, where Utility determines Unauthorized Use is occurring, Utility may refuse or discontinue service without further notice.

If any part of the Customer’s wiring or any other equipment, or the use thereof, is determined by Utility or any other authorized public agency to be unsafe or in violation of applicable laws, ordinances, rules or regulations of public authorities, or is in such condition as to endanger Utility Service Facilities, Utility may discontinue service without further notice.

Utility may also discontinue service in accordance with the provisions of itstariffs, for nonpayment of a delinquent billing for Unauthorized Use and for associated costs, including nonpayment under an amortization agreement.

F. Limitation on Adjustment of Bills for Energy Use.

For any error in billing not defined as Billing Error, Meter Error, or Unauthorized Use, Utility is not required to adjust the bill. However, any billing adjustment not specifically covered in the tariffs for an undercharge or overcharge shall not exceed three (3) years.

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Rule 18
Supply to Premises and Resale
A. Separate Metering.

Separate Premises will not be supplied through the same Meter, nor will the electric loads of such separately metered Premises be aggregated physically, electronically or otherwise except as may be specifically provided for in the Rate Schedule.

B. Other Uses or Premises.

A Customer shall not use electricity received from the Utility upon other Premises, except for Utility’s operating convenience, nor for other purposes than those specified in the Customer’s Application or in the Rate Schedule applied.

C. Customer with Multiple Service Accounts/Meters at a Single Premises.

When a Customer (single enterprise) occupies a single Premises with multiple service accounts/Meters, the readings of such Meters shall not be combined for billing purposes except as provided for in Rule 9. However, if the Customer physically aggregates the electric loads of such multiple service accounts/Meters into a single service account (master-Meter), the account will be provided service under an applicable Rate Schedule.

D. Use by Others.

A Customer shall not charge for electricity received from the Utility and used by any other person, except:

1. Where the charge to tenants is absorbed in the rental for the premises of space occupied; or

2. Where the charge to domestic or non-domestic tenants is absorbed in the rental for the Premises or space occupied, is not separately identified, and does not vary with electrical usage;

3. Where the Customer is the owner, lessee, or operator of a multifamily accommodation and electricity is submetered and resold to tenants at the same rates that the Utility would charge for the service if supplied directly. In such cases, the owner, lessee, or operator shall furnish, install, maintain, and test the submeters.

This electrical usage applies only to the single-family dwelling and excludes other electrical usage, such as swimming pools, recreation rooms, or laundry facilities which are used in common by tenants; or

4. As provided in Section E below.

All energy use, including use by others, supplied through a single Utility Meter is the responsibility of the Customer of record.

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E. Resale of Electricity.

Resale of electricity or submetering of electricity for the purpose of resale is prohibited, except as provided for under Section D.3 above.

Violation of any provision of this Rule shall result in discontinuance of electricity or refusal to provide service, in accordance with Rule 11.

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Rule 19
Reserve for Future Use

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Rule 20
Reserve for Future Use

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Rule 21
Generating Facility Interconnection
A. APPLICABILITY
Applicability: This Rule describes the Interconnection, operating and Metering requirements for Generating Facilities to be connected to Corona Utilities Department’s Electric Utility (CUD) Distribution System. Subject to the requirements of this Rule, CUD will allow the Interconnection of Generating Facilities with its Distribution System.

Definitions: Capitalized terms used in this Rule, and not defined in CUD’s other rules, shall have the meaning ascribed to such terms in Section H of this Rule. The definitions set forth in Section H of this Rule shall only apply to this Rule and may not apply to CUD’s other rules.

Consistent with IEEE 1547: This rule has been revised to be consistent with the requirements of ANSI/IEEE1 1547-2003 Standard for Interconnecting Distributed Resources with Electric Power Systems (IEEE 1547). In some cases, IEEE 1547 language has been adopted directly, in others, IEEE 1547 requirements were interpreted, and this rule’s language was changed to maintain the spirit of both documents.

Language from IEEE 1547 that has been adopted directly (as opposed to paraphrased language or previous language that was determined to be consistent with IEEE 1547) is followed by a citation that lists the Clause from which the language derived. For example, IEEE 1547-4.1.1 is a reference to Clause 4.1.1.

In the event of any conflict between this rule and any of the standards listed herein, the requirements of this rule shall take precedence.

B. GENERAL RULES, RIGHTS AND OBLIGATIONS

1. AUTHORIZATION REQUIRED TO OPERATE: A Producer must comply with this Rule and receive CUD’s express written permission before Parallel Operation of its Generating Facility with CUD’s Distribution System. CUD shall apply this Rule in a non-discriminatory manner and shall not unreasonably withhold its permission for Parallel Operation of Producer’s Generating Facility with CUD’s Distribution System.

2. NO SEPARATE AGREEMENTS REQUIRED FOR OTHER SERVICES: A Producer requiring other electric services from CUD including, but not limited to, Distribution Service during periods of curtailment or interruption of the Producer’s Generating Facility, will comply with these Rules and agrees to abide by all requirements as set forth by CUD for such services in accordance with CUD’s City Council-approved rules.

3. SERVICE NOT PROVIDED WITH INTERCONNECTION: Interconnection with CUD's Distribution System under this Rule does not provide a Producer any rights to utilize CUD's System for the transmission, distribution, or wheeling of electric power.

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4. COMPLIANCE WITH LAWS, RULES AND TARIFF SCHEDULES: A Producer shall ascertain and comply with applicable City Council-approved rules of CUD; applicable Federal Energy Regulatory Commission (FERC) approved rules, rules and regulations; and any local, state or federal law, statute or regulation which applies to the design, siting, construction, installation, operation, or any other aspect of the Producer’s Generating Facility and Interconnection Facilities.

5. DESIGN REVIEWS AND INSPECTIONS: CUD shall have the right to review the design of a Producer's Generating and/or Interconnection Facilities and to inspect a Producer's Generating and/or Interconnection Facilities prior to the commencement of Parallel Operation with CUD’s Distribution System. CUD may require a Producer to make modifications as necessary to comply with the requirements of this Rule. CUD's review and authorization for Parallel Operation shall not be construed as confirming or endorsing the Producer's design or as warranting the Generating and/or Interconnection Facilities' safety, durability, or reliability.

CUD shall not, by reason of such review or lack of review, be responsible for the strength, adequacy, or capacity of such equipment.

6. RIGHT TO ACCESS: A Producer’s Generating Facility and/or Interconnection Facilities shall be reasonably accessible to CUD personnel as necessary for CUD to perform its duties and exercise its rights under its rules approved by the City Council, and any Interconnection requirements of CUD.

7. CONFIDENTIALITY OF INFORMATION: Any information pertaining to Generating and/or Interconnection Facilities provided to CUD by a Producer shall be treated by CUD in a confidential manner. CUD shall not use information contained in the Application to propose discounted rates to the customer unless authorized to do so by the Customer or the information is provided to CUD by the Customer through other means.

8. PRUDENT OPERATION AND MAINTENANCE REQUIRED: A Producer shall operate and maintain its Generating Facility and Interconnection Facilities in accordance with Prudent Electrical Practices and shall maintain compliance with this Rule.

9. CURTAILMENT AND DISCONNECTION: CUD may limit the operation or disconnect or require the disconnection of a Producer’s Generating Facility from CUD’s Distribution System at any time, with or without notice, in the event of an Emergency, or to correct Unsafe Operating Conditions. CUD may also limit the operation or disconnect or require the disconnection of a Producer’s Generating Facility from CUD’s Distribution System upon the provision of reasonable written notice: 1) to allow for routine maintenance, repairs or modifications to CUD’s Distribution System; 2) upon CUD’s determination that a Producer’s Generating Facility is not in compliance with this Rule; or 3) upon failure of Producer to meet the requirements of CUD. Upon the Producer’s written request, CUD shall provide a written explanation of the reason for such curtailment or disconnection.

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C. APPLICATION AND INTERCONNECTION PROCESS

1. APPLICATION PROCESS
a. Applicant Initiates Contact with CUD: Upon request, CUD will provide information and documents (such as requirements, Application, technical information, listing of Certified Equipment, Initial and Supplemental Review deposit information, applicable tariff schedules and Metering requirements and Rules) to a potential Applicant. Unless otherwise agreed upon, all such information shall normally be sent to an Applicant within three (3) business days following the initial request from the Applicant. CUD will establish an individual representative as the single point of contact for the Applicant but may allocate responsibilities among its staff to best coordinate the Interconnection of an Applicant’s Generating Facility.
b. Applicant Completes an Application: All Applicants shall complete and file an Application and supply any relevant additional information requested by CUD. CUD shall make a determination regarding the appropriate assigned schedule for the applicant based upon available capacity. If the applicant falls within five percent (5%) of CUD’s maximum coincident peak demand in the 2023 fiscal year “Net Energy Metering (NEM) Capacity Value”, the applicant shall fall under the NEM schedule. If the applicant falls outside of the NEM Capacity Value, they shall be assigned to the Eligible Renewable Generation (ERG) schedule. When applicable per Table C.1, an Initial Review deposit as listed in the Citywide Master Fee Recovery Schedule shall be included with the Application.
1) Normally, within 10 business days of receiving the Application, CUD shall acknowledge its receipt and state whether the Application has been completed adequately. If defects are noted, CUD and Applicant shall cooperate in a timely manner to establish a satisfactory Application.
2) The Initial Review deposit shall be waived for Net Energy Metering Applications requesting Interconnection.
3) The deposit associated with the Initial Review will be returned to the Applicant if the Application is rejected by CUD exactly as submitted or the Applicant retracts the Application.
4) Applications that are over one year old (from the date of CUD’s acknowledgement) without a completed application, or a Generating Facility that has not been approved for parallel operation within one year of completion of all applicable review and/or studies are subject to cancellation by CUD; however, CUD may not cancel an Application if the Producer provides reasonable evidence that the project is still active.
5) The applicant may propose, and CUD may agree to reduced costs for reviewing atypical Applications, such as Applications submitted for multiple Generators, multiple sites, or otherwise as conditions warrant.

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c. CUD Performs an Initial and Supplemental Review and Develops Preliminary Cost Estimates and Interconnection Requirements.
1) Upon receipt of a satisfactorily completed Application and any additional information necessary to evaluate the Interconnection of a Generating Facility, CUD shall perform an Initial Review using the process defined in Section I. The Initial Review determines if: (a) the Generating Facility qualifies for Simplified Interconnection; or (b) the Generating Facility requires a Supplemental Review. 2) CUD shall complete its Initial Review, absent any extraordinary circumstances, within 10 business days after its determination that the Application is complete.

If the Initial Review determines the proposed Generating Facility can be Interconnected by means of a Simplified Interconnection, CUD will provide the Applicant with an Interconnection Authorization. Upon completion of the Initial Review, the difference between the deposit and the actual cost of the Review will be refunded or billed to the Applicant as appropriate. 3) If the Generating Facility does not pass the Initial Review for Simplified Interconnection as proposed, CUD will notify the applicant and perform a Supplemental Review as described in Section I. Applicant shall pay an additional deposit for the Supplemental Review per the Citywide Master Fee Recovery Schedule, unless the Application is withdrawn. The Supplemental Review will result in CUD providing either: (a) Interconnection requirements beyond those for a Simplified Interconnection, and an Interconnection Authorization; or (b) a cost estimate and schedule for an Interconnection Study.

The Supplemental Review shall be completed, absent any extraordinary circumstances, within 20 business days of receipt of a completed Application and fees. Upon completion of the Supplemental Review, the difference between the deposit and the actual cost of the Review will be refunded or billed to the Applicant as appropriate.

The Supplemental Review deposit shall be waived for Net Energy Metering Applications requesting Interconnection pursuant to Sections 2827, 2827.8, 2827.9, or 2827.10 of the Public Utilities Code.
d. When Required, Applicant and CUD Commit to Additional Interconnection Study Steps. When a Supplemental Review reveals that the proposed Generating Facility cannot be Interconnected to CUD’s Distribution System by means of a Simplified Interconnection, or that significant Interconnection Facilities installed on CUD’s system or Distribution System modifications will be needed to accommodate an Applicant’s Generating Facility, CUD and Applicant shall enter into an agreement that provides for CUD to perform additional studies, facility design, and engineering and to provide detailed cost estimates for fixed price or actual cost billing to the Applicant at the Applicant’s expense. The Interconnection Study agreement shall set forth CUD’s estimated schedule and charges for completing such work. Generating Facilities eligible for Net Energy Metering under Public Utilities Code Section 2827, 2827.8, 2827.9, or 2827.10 are exempt from any costs associated with Interconnection Studies.

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Table C.1 Summary of Deposits and Exemptions
Facility Type Initial
Review
Deposit
Supplemental
Review Deposit
Interconnection
Study Deposit
Additional
Commissioning Test
Verification
Non-Net
Energy
Metering
See
Citywide
Master Fee
Recovery
Schedule *
As Specified by
CUD
As Specified by
CUD
Actual cost
* Subject to refund pursuant to Section C.1.b.3
Table C.2.A Summary of New Generator Cost Responsibility for Multiple Tariff Interconnections Charge NEM Non-NEM
Simultaneous NEM
and Non-NEM
Initial Review Deposit X X
Supplemental Review Deposit X X
Detailed Interconnection Study Cost X X
Interconnection Facilities Cost X X X
Distribution System Modifications Cost X X
Table C.2.B Summary of Existing Generator Cost Responsibility for Multiple Tariff Interconnections Charge NEM to NEM NEM to Non-NEM
Simultaneous NEM
and Non-NEM
Initial Review Deposit X X
Supplemental Review Deposit X X
Detailed Interconnection Study Cost X X
Interconnection Facilities Cost X X X
Distribution System Modifications Cost X X
Proration will be based upon the annual expected energy output (kWh) derived from the nameplate of the generator(s) modified by technology-specific capacity/availability factors of all NEM eligible versus non-NEM eligible generators for the costs that cannot be clearly assigned to either type of tariff.

Change of operating of a non-NEM eligible generator at any time to export is treated as a simultaneous NEM and non-NEM application, resulting in associated costs being allocated to the producer.

2. INTERCONNECTION PROCESS
a. Applicant shall comply with the Interconnection Requirements as stated in this Rule.

CUD shall review with the Applicant all requirements for Interconnection and Net Energy Metering (or Eligible Renewable Generation) appropriate for the Applicant’s Generating Facility and desired mode of operation. These requirements are detailed in Rule 21A, Interconnection Rules, Terms & Conditions. Rule 21A sets forth CUD’s and the Applicant’s responsibilities, completion schedules, and fixed price or estimated costs for the required work.

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b. Where Applicable (for commercial systems greater than 1MW), CUD or Producer Installs Required Interconnection Facilities or Modifies CUD’s Distribution System.

After executing the applicable agreements, CUD or Producer will commence construction/ installation of CUD’s Distribution System modifications or Interconnection Facilities which have been identified in the agreement and application.

The parties will use good faith efforts to meet schedules and estimated costs as appropriate.
c. Producer Arranges for and Completes Commissioning Testing of Generating Facility and Producer’s Interconnection Facilities. The Producer is responsible for testing new Generating Facilities and associated Interconnection Facilities according to Section J.5 to ensure compliance with the safety and reliability provisions of this Rule prior to being operated in parallel with CUD’s Distribution System. For non-Certified Equipment, the Producer shall develop a written testing plan to be submitted to CUD for its review and acceptance. Alternatively, the Producer and CUD may agree to have CUD conduct the required testing at the Producer’s expense. Where applicable, the test plan shall include the installation test procedures published by the manufacturer of the generation or Interconnection equipment. Facility testing shall be conducted at a mutually agreeable time, and depending on who conducts the test, CUD or Producer shall be given the opportunity to witness the tests.
d. CUD Authorizes Parallel Operation or Momentary Parallel Operation. CUD shall authorize the Producer’s Generating Facility for Parallel Operation or Momentary Parallel Operation with CUD’s Distribution System, in writing, within 5 calendar days of satisfactory compliance with the terms of all applicable Rules. Compliance may include, but not be limited to, provision of any required documentation and satisfactorily completing any required inspections or tests as described herein or in the agreements formed between the Producer and CUD. A Producer shall not commence Parallel Operation of its Generating Facility with CUD’s system unless it has received CUD’s express written permission to do so.

For Net Energy Metering Generating or Eligible Renewable Generation facilities, CUD authorization for Parallel Operation shall normally be provided no later than 30 business days following CUD’s receipt of 1) a completed Net Energy Metering or Eligible Renewable Generation Application including all supporting documents and required payments; 2) a completed signed Net Energy Metering or Eligible Renewable Generation Interconnection Agreement; and 3) evidence of the Producer’s final inspection clearance from the governmental authority having jurisdiction over the Generating Facility. If the 30-day period cannot be met, the CUD shall notify the Applicant and the Commission.

D. GENERATING FACILITY DESIGN AND OPERATING REQUIREMENTS This section has been revised to be consistent with the requirements of ANSI/IEEE 1547-2003 Standard for Interconnecting Distributed Resources with Electric Power Systems (IEEE 1547).

1. General Interconnection and Protective Function Requirements

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The Protective Functions and requirements of this Rule are designed to protect CUD’s Distribution System and not the Generating Facility. A Producer shall be solely responsible for providing adequate protection for its Generating Facility and Interconnection Facilities. The Producer's Protective Functions shall not impact the operation of other Protective Functions utilized on CUD’s Distribution System in a manner that would affect CUD's capability of providing reliable service to its Customers.
a. Protective Functions Required: Generating Facilities operating in parallel with CUD’s Distribution System shall be equipped with the following Protective Functions to sense abnormal conditions on CUD’s Distribution System and cause the Generating Facility to be automatically disconnected from CUD’s Distribution System or to prevent the Generating Facility from being connected to CUD’s Distribution System inappropriately:
1) Over and under voltage trip functions and over and under frequency trip functions;
2) A voltage and frequency sensing and time-delay function to prevent the Generating Facility from energizing a de-energized Distribution System circuit and to prevent the Generating Facility from reconnecting with CUD’s Distribution System unless CUD’s Distribution System service voltage and frequency is within the ANSI C84.1-1995 Table 1 Range B Voltage Range of 106V to 127V (on a 120V basis), inclusive, and a frequency range of 59.3 Hz to

60.5 Hz, inclusive, and are stable for at least 60 seconds; and 3) A function to prevent the Generating Facility from contributing to the formation of an Unintended Island and cease to energize the CUD’s Distribution System within two seconds of the formation of an Unintended Island.

The Generating Facility shall cease to energize CUD’s Distribution System for faults on CUD’s Distribution System circuit to which it is connected (IEEE1547-4.2.1). The Generating Facility shall cease to energize CUD’s Distribution circuit prior to re-closure by CUD’s Distribution System equipment (IEEE1547-4.2.2).
b. Momentary Paralleling Generating Facilities. With CUD’s approval, the transfer switch or scheme used to transfer the Producer’s loads from CUD’s Distribution System to Producer’s Generating Facility may be used in lieu of the Protective Functions required for Parallel Operation.
c. Suitable Equipment Required. Circuit breakers or other interrupting equipment located at the Point of Common Coupling must be Certified or "Listed" (as defined in Article 100, the Definitions Section of the National Electrical Code) as suitable for their intended application. This includes being capable of interrupting the maximum available fault current expected at their location. Producer’s Generating Facility and Interconnection Facilities shall be designed so that the failure of any single device or component shall not potentially compromise the safety and reliability of CUD’s

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Distribution System. The Generating Facility paralleling-device shall be capable of withstanding 220% of the Interconnection Facility rated voltage (IEEE1547-4.1.8.3).

The Interconnection Facility shall have the capability to withstand voltage and current surges in accordance with the environments defined in IEEE Std C62.41.2-2002 or IEEE Std C37.90.1-2002 as applicable and as described in J.3.e (IEEE1547-4.1.8.2). d. Visible Disconnect Required. When required by CUD’s operating practices, the Producer shall furnish and install a ganged, manually-operated isolating switch (or a comparable device mutually agreed upon by CUD and the Producer) near the Point of Interconnection to isolate the Generating Facility from CUD’s Distribution System. The device does not have to be rated for load break nor provide over-current protection.

The device must:
1) allow visible verification that separation has been accomplished. (This requirement may be met by opening the enclosure to observe contact separation.)
2) include markings or signage that clearly indicate open and closed positions. 3) be capable of being reached quickly and conveniently 24 hours a day by CUD personnel for construction, operation, maintenance, inspection, testing or reading, without obstacles or requiring those seeking access to obtain keys, special permission, or security clearances.
4) be capable of being locked in the open position.
5) be clearly marked on the submitted single line diagram and its type and location approved by the CUD prior to installation. If the device is not adjacent to the Point of Common Coupling, permanent signage must be installed at a CUDapproved location providing a clear description of the location of the device.

Generating Facilities with Non-Islanding inverters totaling one (1) kilovolt-ampere (kVA) or less are exempt from this requirement.
e. Drawings Required. Prior to Parallel Operation or Momentary Parallel Operation of the Generating Facility, CUD shall approve the Producer's Protective Function and control diagrams. Generating Facilities equipped with Protective Functions and a control scheme previously approved by CUD for system-wide application or only Certified Equipment may satisfy this requirement by reference to previously approved drawings and diagrams.
f. Generating Facility Conditions Not Identified. In the event this Rule does not address the Interconnection conditions for a Particular Generating Facility, CUD and Producer may agree upon other arrangements.

2. PREVENTION OF INTERFERENCE: The Producer shall not operate Generating or Interconnection Facilities that superimpose a voltage or current upon CUD’s Distribution

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System that interferes with CUD operations, service to CUD customers, or communication facilities. If such interference occurs, the Producer must diligently pursue and take corrective action at its own expense after being given notice and reasonable time to do so by CUD. If the Producer does not take corrective action in a timely manner, or continues to operate the facilities causing interference without restriction or limit, CUD may, without liability, disconnect the Producer's facilities from CUD’s Distribution System, in accordance with Section B.9 of this Rule. To eliminate undesirable interference caused by its operation, each Generating Facility shall meet the following criteria:
a. Voltage Regulation: The Generating Facility shall not actively regulate the voltage at the Point of Common Coupling while in parallel with CUD’s Distribution System. The Generating Facility shall not cause the service voltage at other customers to go outside the requirements of ANSI C84.1-1995, Range A (IEEE1547-4.1.1). b. Operating Voltage Range: The voltage ranges in Table D.1 define protective trip limits for the Protective Function and are not intended to define or imply a voltage regulation Function. Generating Facilities shall cease to energize CUD’s Distribution System within the prescribed trip time whenever the voltage at the Point of Common Coupling deviates from the allowable voltage operating range. The Protective Function shall detect and respond to voltage on all phases to which the Generating Facility is connected.
1) Generating Facilities (30 kVA or less). Generating Facilities with a Gross Nameplate Rating of 30 kVA or less shall be capable of operating within the voltage range normally experienced on CUD’s Distribution System. The operating range shall be selected in a manner that minimizes nuisance tripping between 106 volts and 132 volts on a 120-volt base (88%-110% of nominal voltage). Voltage shall be detected at either the Point of Common Coupling or the Point of Interconnection.
2) Generating Facilities (greater than 30 kVA). CUD may have specific operating voltage ranges for Generating Facilities with Gross Nameplate Ratings greater than 30 kVA and may require adjustable operating voltage settings. In the absence of such requirements, the Generating Facility shall operate at a range between 88% and 110% of the applicable interconnection voltage. Voltage shall be detected at either the Point of Common Coupling or the Point of Interconnection, with settings compensated to account for the voltage at the Point of Common Coupling, Generating Facilities that are Certified NonIslanding or that meet one of the options of the Export Screen (Section I.3.b) may detect voltage at the Point of Interconnection without compensation. 4) Voltage Disturbances. Whenever CUD’s Distribution System voltage at the Point of Common Coupling varies from and remains outside normal (nominally 120 volts) for the predetermined parameters set forth in Table D-1, the Generating Facility’s Protective Functions shall cause the Generator(s) to become isolated from CUD’s Distribution System:

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Table D.1 Voltage Trip Settings
Voltage at Point of Common Coupling Maximum Trip Time* # of Cycles (Assuming 120 V Base) % of Nominal Voltage (Assuming 60Hz Nominal) Seconds
Less than 60 Volts Less than 50% 10 Cycles 0.16 Seconds Greater than of equal to
50% but less than 88% 120 Cycles 2 Seconds
Greater than or equal to 106
volts but less than 132 volts
Greater than of equal to
88% but less than 110% Normal Operation
Greater than or equal to 132
volts but less than 144 volts
Greater than of equal to
110% but less than 120% 60 Cycles 1 Second
Greater than 144Volts Greater than 120% 10 Cycles 0.16 Seconds * "Maximum Trip time" refers to the time between the onset of the abnormal condition and the Generating Facility ceasing to energize CUD’s Distribution System. Protective Function sensing equipment and circuits may remain connected to CUD’s Distribution System to allow sensing of electrical conditions for use by the "reconnect" feature. The purpose of the allowed time delay is to allow a Generating Facility to “ride through” short-term disturbances to avoid nuisance tripping. Set points shall not be user adjustable (though they may be field adjustable by qualified personnel). For Generating Facilities with a Gross Nameplate Rating greater than 30 kVA, set points shall be field adjustable and different voltage set points and trip times from those in Table D.1 may be negotiated with CUD.
c. Paralleling. The Generating Facility shall parallel with CUD’s Distribution System without causing a voltage fluctuation at the Point of Common Coupling greater than ±5% of the prevailing voltage level of CUD’s Distribution System at the Point of Common Coupling and meet the flicker requirements of Section D.2.d. Section J provides technology-specific tests for evaluating the paralleling Function. (IEEE1547-

4.1.3)
d. Flicker. The Generating Facility shall not create objectionable flicker for other customers on CUD’s Distribution System. To minimize the adverse voltage effects experienced by other customers (IEEE1547-4.3.2), flicker at the Point of Common Coupling caused by the Generating Facility should not exceed the limits defined by the "Maximum Borderline of Irritation Curve" identified in IEEE 519-1992 (IEEE Recommended Practices and Requirements for Harmonic Control in Electric Power Systems, IEEE STD 519-1992). This requirement is necessary to minimize the adverse voltage effects experienced by other customers on CUD’s Distribution System.

Generators may be connected and brought up to synchronous speed (as an induction motor) provided these flicker limits are not exceeded.
e. Integration with CUD’s Distribution System Grounding. The grounding scheme of the Generating Facility interconnection shall not cause over-voltages that exceed the rating

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of the equipment connected to the CUD’s Distribution System and shall not disrupt the coordination of the ground fault protection on the CUD’s Distribution System (IEEE1547-4.1.2) (See Section I.3.h).
f. Frequency: CUD controls system frequency, and the Generating Facility shall operate in synchronism with the CUD’s Distribution System. Whenever CUD’s Distribution System frequency at the Point of Common Coupling varies from and remains outside normal (nominally 60 Hz) by the predetermined amounts set forth in Table D.2, the Generating Facility’s Protective Functions shall cease to energize CUD’s Distribution System within the stated maximum trip time.

Table D.2 Frequency Trip Settings
Frequency Range Maximum Trip Time [1]
Generating
Facility Rating (Assuming 60Hz Nominal) (Assuming 60 Cycles per Second) Less or equal to
30kW Less than 59.3 Hz Greater than 60.5 Hz 10 Cycles
Greater than
30kW Less than 57 Hz 10 Cycles
Less than an adjustable value between 59.8Hz and
57 Hz but greater than 57 Hz. [2]
Adjustable between 10 and
18,000 Cycles. [2, 3]
Greater than 60.5 Hz 10 Cycles
[1] -"Maximum Trip time" refers to the time between the onset of the abnormal condition and the Generating Facility ceasing to energize CUD’s Distribution System. Protective Function sensing equipment and circuits may remain connected to CUD’s Distribution System to allow sensing of electrical conditions for use by the "reconnect" feature. The purpose of the allowed time delay is to allow a Generating Facility to “ride through” short-term disturbances to avoid nuisance tripping. Set points shall not be user adjustable (though they may be field adjustable by qualified personnel). For Generating Facilities with a Gross Nameplate Rating greater than 30 kVA, set points shall be field adjustable and different voltage set points and trip times from those in Table D.2 may be negotiated with CUD. [2] - Unless otherwise required by CUD, a trip frequency of 59.3 Hz and a maximum trip time of 10 cycles shall be used
[3] - When a 10 cycle Maximum trip time is used, a second under frequency trip setting is not required. g. Harmonics. When the Generating Facility is serving balanced linear loads, harmonic current injection into CUD’s Distribution System at the PCC shall not exceed the limits stated below in Table D.3. The harmonic current injections shall be exclusive of any harmonic currents due to harmonic voltage distortion present in CUD’s Distribution

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System without the Generating Facility connected (IEEE1547-4.3.3). The harmonic distortion of a Generating Facility located at a Customer's site shall be evaluated using the same criteria as for the Host Loads.

Table D.3 Maximum harmonic current distortion in percent of current (I) [1,2] Individual harmonic
order, h (odd
harmonics) [3]
h < 11 11 ≤ h < 17 17 ≤ h < 23 23 ≤ h < 35 35 ≤ h Total demand distortion
(TDD)
Max Distortion (%) 4.0 2.0 1.5 0.6 0.3 5.0
[1] - IEEE1547-4.3.3
[2] - I = the greater of the maximum Host Load current average demand over 15 or 30 minutes without the Generating Facility, or the Generating Facility rated current capacity (transformed to the Point of Common Coupling when a transformer exists between the Generating Facility and the Point of Common Coupling). [3] - Even harmonics are limited to 25% of the odd harmonic limits above. h. Direct Current Injection. Generating Facilities should not inject direct current greater than 0.5% of rated output current into CUD’s Distribution System. i. Power Factor. Each Generator in a Generating Facility shall be capable of operating at some point within a power factor range from 0.9 leading to 0.9 lagging. Operation outside this range is acceptable provided the reactive power of the Generating Facility is used to meet the reactive power needs of the Host Loads or that reactive power is otherwise provided under tariff by CUD. The Producer shall notify CUD if it is using the Generating Facility for power factor correction. Unless otherwise agreed upon by the Producer and CUD, Generating Facilities shall automatically regulate power factor, not voltage, while operating in parallel with CUD’s Distribution System.

3. TECHNOLOGY SPECIFIC REQUIREMENTS
a. Three-Phase Synchronous Generators. For three-phase Generators, the Generating Facility circuit breakers shall be three-phase devices with electronic or electromechanical control. The Producer shall be responsible for properly synchronizing its Generating Facility with CUD’s Distribution System by means of either manual or automatic synchronizing equipment. Automatic synchronizing is required for all synchronous Generators that have a Short Circuit Contribution Ratio (SCCR) exceeding 0.05. Loss of synchronism protection is not required except as may be necessary to meet Section D.2.d (Flicker) (IEEE1547-4.2.5). Unless otherwise agreed upon by the Producer and CUD, synchronous Generators shall automatically regulate power factor, not voltage, while operating in parallel with CUD’s Distribution System. A power system stabilization function is specifically not required for Generating Facilities under 10 MW Net Nameplate Rating.

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b. Induction Generators. Induction Generators (except self-excited Induction Generators) do not require a synchronizing Function. Starting or rapid load fluctuations on induction generators can adversely impact CUD’s Distribution System's voltage. Corrective stepswitched capacitors or other techniques may be necessary and may cause undesirable ferro-resonance. When these counter measures (e.g., additional capacitors) are installed on the Producer's side of the Point of Common Coupling, CUD must review these measures. Additional equipment may be required as determined in a Supplemental Review or an Interconnection Study.
c. Inverters. Utility-interactive inverters do not require separate synchronizing equipment.

Non-utility-interactive or “stand-alone” inverters shall not be used for Parallel Operation with CUD’s Distribution System.
d. Single-Phase Generators. For single-phase Generators connected to a shared singlephase secondary system, the maximum Net Nameplate Rating of the Generating Facilities shall be 20 kVA. Generators connected to a center-tapped neutral 240-volt service must be installed such that no more than 6 kVA of imbalanced power is applied to the two “legs” of the 240-volt service. For Dedicated Distribution Transformer services, the maximum Net Nameplate Rating of a single-phase Generating Facility shall be the transformer nameplate rating.

4. SUPPLEMENTAL GENERATING FACILITY REQUIREMENTS
a. The maximum solar generation capacity that will be approved to be connected to each meter is up to 50% of the meter minimum daytime load. The meter minimum daytime load will be determined by analyzing one year of historic data, while ignoring any extraordinary events (outages, partial lights, etc.), unless there have been recent major changes to the daily demand schedule. In that case, the most recent information will be evaluated.
b. For 12kV distribution circuits with multiple solar projects connected, the maximum solar generation capacity that will be approved will be up to 50% of the total minimum daytime coincident circuit load, including any solar generation previously approved on the circuit. Capacity will be approved on a first come and first serve basis. 50% of the minimum daytime coincident circuit load will be determined by analyzing one year of historic data, while ignoring any extraordinary events (outages, partial lights, etc.), unless there have been recent major changes to the daily demand schedule. In that case, the most recent information will be evaluated.
c. Fault Detection. A Generating Facility with a short circuit contribution ratio exceeding

0.1 or one that does not cease to energize CUD’s Distribution System within two seconds of the formation of an Unintended Island shall be equipped with Protective Functions designed to detect Distribution System faults, both line-to-line and line-toground and shall cease to energize CUD’s Distribution System within two seconds of the initiation of a fault.
d. Transfer Trip. For a Generating Facility that cannot detect Distribution System faults

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(both line-to-line and line-to-ground) or the formation of an Unintended Island and cease to energize CUD’s Distribution System within two seconds, CUD may require a Transfer Trip system or an equivalent Protective Function. e. Reclose Blocking. Where the aggregate Generating Facility, capacity exceeds 15% of the peak load on any automatic reclosing device, CUD may require additional Protective Functions, including, but not limited to reclose-blocking on some of the automatic reclosing devices.
f. The Generating Facility may require additional approvals from other agencies before the Facility is allowed to begin construction.

E. INTERCONNECTION FACILITIES AND DISTRIBUTION SYSTEM MODIFICATIONS

1. SCOPE AND OWNERSHIP OF INTERCONNECTION FACILITIES AND

DISTRIBUTION SYSTEM MODIFICATIONS
a. Scope. Parallel Operation of Generating Facilities may require Interconnection Facilities or modifications to CUD’s Distribution System (“Distribution System modifications”). The type, extent and costs of Interconnection Facilities and Distribution System modifications shall be consistent with this Rule and determined through the Supplemental Review and/or Interconnection Studies described in Section C.
b. Ownership. Interconnection Facilities installed on Producer’s side of the Point of Common Coupling may be owned, operated and maintained by the Producer or CUD. Interconnection Facilities installed on CUD’s side of the Point of Common Coupling and Distribution System modifications shall be owned, operated and maintained only by CUD.

2. RESPONSIBILITY OF COSTS OF INTERCONNECTING A GENERATING

FACILITY
a. Review, Study, and Additional Commissioning Test Verification (pre-parallel inspections) Costs. A producer shall be responsible for the reasonably incurred costs of the review’s studies, and additional Commissioning Test verifications (pre-parallel inspections) conducted pursuant to Section C of the Rule. If the initial Commissioning Test verification (pre-parallel inspection) is not successful through no fault of CUD, CUD may impose upon the Producer a cost-based charge for subsequent Commissioning Test verifications (pre-parallel inspections). All Costs for additional Commissioning Test verifications (preparallel inspections) shall be paid by Producer within thirty days of receipt of CUD’s invoice. Additional costs, if any, will be specified on the invoice. If the initial Commissioning test (pre-paralleling inspection) is not successful through the fault of the CUD, that visit will not be considered the initial Commissioning Test (pre-parallel inspection).

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b. Facility Costs. A Producer shall be responsible for all costs associated with Interconnection Facilities owned by the Producer. The Producer shall also be responsible for any costs reasonably incurred by CUD in providing, operating, or maintaining the Interconnection Facilities and Distribution System modifications required solely for the Interconnection of the Producer’s Generating Facility with CUD’s Distribution System. Generating Facilities eligible for Net Energy Metering under California Public Utilities Code Sections 2827, 2827.8, 2827.9, or 2827.10 are exempt from any costs associated with Distribution System modifications.
c. Separation of Costs. Should CUD combine the installation of Interconnection Facilities or Distribution System modifications required for the Interconnection of a Generating Facility with modifications to CUD’s Distribution System to serve other Customers or Producers, CUD shall not include the costs of such separate or incremental facilities in the amounts billed to the Producer.

3. INSTALLATION OF INTERCONNECTION FACILITIES AND DISTRIBUTION

SYSTEM MODIFICATIONS
a. Agreement Required. The costs for Interconnection Facilities and Distribution System modifications shall be paid by the Producer pursuant to the provisions contained in the Interconnection Agreement.
b. Interconnection Facilities and Distribution System Modifications. Except as provided for in Sections E.2.b. and E.3.c. of this Rule, Interconnection Facilities connected to CUD’s side of the Point of Common Coupling and Distribution System modifications shall be provided, installed, owned and maintained by CUD at Producer’s expense, or may be installed by a third party upon approval by CUD.
c. Third-Party Installations. Subject to the approval of CUD, a Producer may at its option employ a qualified contractor to provide and install Interconnection Facilities or Producer paid Distribution System modifications, to be owned and operated by CUD, on CUD’s side of the Point of Common Coupling. Such Interconnection Facilities and Distribution System modifications shall be installed in accordance with CUD's design and specifications. Upon final inspection and acceptance by CUD, the Producer shall transfer ownership of such Producer installed Interconnection Facilities or Distribution System modifications to CUD and such facilities shall thereafter be owned and maintained by CUD. The Producer shall pay CUD's reasonable cost of design, administration, and monitoring of the installation for such facilities to ensure compliance with CUD's requirements. The Producer shall also be responsible for all costs associated with the transfer of Producer installed Interconnection Facilities and Distribution System modifications to CUD.

F. METERING, MONITORING AND TELEMETRY

1. GENERAL REQUIREMENTS: All Generating Facilities shall be metered in accordance with

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this Section F and shall meet all applicable standards of CUD contained in CUD’s applicable rules and published CUD manuals dealing with specifications.

2. METERING BY NON-CUD PARTIES: The ownership, installation, operation, reading and testing of revenue Metering Equipment for Generating Facilities shall be by CUD.

3. NET GENERATION OUTPUT METERING (NGOM): Generating Facilities’ customers may be required to install NGOM for evaluation, monitoring and verification purposes, to satisfy applicable CAISO reliability requirements, and for Distribution System planning and operations.

The relevant factors in determining the need for NGOM are as listed below:
a. Data requirements in proportion to need for information; b. Producer’s election to install equipment that adequately addresses CUD’s operational requirements;
c. Accuracy and type of required Metering consistent with purposes of collecting data; d. Cost of Metering relative to the need for and accuracy of the data; e. The Generating Facility’s size relative to the cost of the Meter/monitoring; f. Other means of obtaining the data (e.g., Generating Facility logs, proxy data etc.); g. Requirements under any interconnection Agreement with the Producer.

The requirements in this Section may not apply to Metering of Generating Facilities operating under CUD’s Net Energy Metering tariff pursuant to the California Public Utilities Cod Section 2827, et seq.

Nothing in this Section F.3 supersedes Section B.4.

4. POINT OF COMMON COUPLING METERING: For purposes of assessing CUD charges for retail service, the Producer’s PCC Metering shall be a bi-directional meter so that power deliveries to and from the Producer’s site can be separately recorded. Alternately, the Producer may, at its sole option and cost, require CUD to install multi-metering equipment to separately record power deliveries to CUD’s Distribution System and retail purchases from CUD. Where necessary, such PCC Metering shall be designed to prevent reverse registration.

5. TELEMETERING: If the nameplate rating of the Generating Facility is 1 MW or greater, Telemetering equipment at the Net Generator Output Metering location may be required at the Producer's expense. If the Generating Facility is Interconnected to a portion of CUD’s Distribution System operating at a voltage below 10 kV, then Telemetering equipment may be required on Generating Facilities 250 kW or greater. CUD shall only require Telemetering to the extent that less intrusive and/or more cost effective options for providing the necessary data in real time are not available.

6. LOCATION: Where CUD-owned Metering is located on the Producer’s premises, Producer shall provide, at no expense to CUD, a suitable location for all such Metering Equipment.

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7. COSTS OF METERING: The Producer will bear all costs of the Metering required by this Rule, including the incremental costs of operating and maintaining the Metering Equipment.

G. DISPUTE RESOLUTION PROCESS
The following procedures will apply for disputes arising from this Rule:

1. The City Council shall have jurisdiction to interpret, add, delete or modify any provision of this Rule or of any agreements entered into between CUD and the Producer to implement this tariff (“The Implementing Agreements") and to resolve disputes regarding CUD’s performance of its obligations under its rules, the applicable agreements, and requirements related to the Interconnection of the Producer’s Generating or Interconnection Facilities pursuant to this Rule.

2. The dispute shall be submitted in writing by the Producer to CUD. Authorized representatives from both Parties shall meet and confer to try to resolve the dispute. If the Parties cannot resolve the dispute, the dispute will be submitted to the City Council for resolution. Their decision shall be final.

3. Pending resolution of any dispute under this Section, the Parties shall proceed diligently with the performance of their respective obligations under this Rule and the Implementing Agreements, unless the Implementing Agreements have been terminated. Disputes as to the application and implementation of this Section shall be subject to resolution pursuant to the procedures set forth in this Section.

H. DEFINITIONS
The definitions in this Section H are applicable only to this Rule, the Application and Interconnection Agreements.

Anti-Islanding: A control scheme installed as part of the Generating Facility or Interconnection Facilities that senses and prevents the formation of an Unintended Island.

Applicant: The entity submitting an Application for Interconnection pursuant to this Rule.

Application: A Commission-approved standard form submitted to CUD for Interconnection of a Generating Facility.

Certification Test: A test pursuant to this Rule that verifies conformance of certain equipment with Commission-approved performance standards in order to be classified as Certified Equipment.

Certification Tests are performed by NRTLs.

Certification; Certified; Certificate: The documented results of a successful Certification Testing.

Certified Equipment: Equipment that has passed all required Certification Tests.

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Commissioning Test: A test performed during the commissioning of all or part of a Generating Facility to achieve one or more of the following:
• Verify specific aspects of its performance;
• Calibrate its instrumentation; and
• Establish instrument or Protective Function set-points.

Customer: The entity that receives or is entitled to receive Distribution Service through the CUD’s Distribution System.

Dedicated Transformer; Dedicated Distribution Transformer: A transformer that provides electricity service to a single Customer. The Customer may or may not have a Generating Facility.

Device: A mechanism or piece of equipment designed to serve a purpose or perform a function. The term may be used interchangeably with the terms “equipment” and “function” without intentional difference in meaning. See also Function and Protective Function.

Distribution Service: All services required by, or provided to, a Customer pursuant to the approved rules of CUD other than services directly related to the Interconnection of a Generating Facility under this Rule.

Distribution System: All electrical wires, equipment, and other facilities owned or provided by CUD, other than Interconnection Facilities, by which CUD provides Distribution Service to its Customers.

Emergency: An actual or imminent condition or situation, which jeopardizes CUD’s Distribution System Integrity.

Field Testing: Testing performed in the field to determine whether equipment meets CUD’s requirements for safe and reliable Interconnection.

Function: Some combination of hardware and software designed to provide specific features or capabilities. Its use, as in Protective Function, is intended to encompass a range of implementations from a single-purpose device to a section of software and specific pieces of hardware within a larger piece of equipment to a collection of devices and software.

Generating Facility: All Generators, electrical wires, equipment, and other facilities owned or provided by Producer for the purpose of producing electric power.

Generator: A device converting mechanical, chemical or solar energy into electrical energy, including all of its protective and control Functions and structural appurtenances. One or more Generators comprise a Generating Facility.

Gross Nameplate Rating; Gross Nameplate Capacity: The total gross generating capacity of a Generator or Generating Facility as designated by the manufacturer(s) of the Generator(s).

Host Load: The electrical power, less the Generator auxiliary load, consumed by the Customer, to which the Generating Facility is connected.

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Initial Review: The review by CUD, following receipt of an Application, to determine the following:
(a) the Generating Facility qualifies for Simplified Interconnection; or (b) if the Generating Facility can be made to qualify for Interconnection with a Supplemental Review determining any additional requirements.

In-rush Current: The current determined by the In-rush Current Test.

Interconnection Agreement: The Interconnection Agreement has been replaced by Rule 21 A – Interconnection Responsibilities, Terms and Conditions. This rule details the rights and obligations to affect or end Interconnection. For the purposes of this Rule, Net Energy Metering or Power Purchase Agreements authorized by the Commission are also defined as Interconnection Agreements.

Interconnection; Interconnected: The physical connection of a Generating Facility in accordance with the requirements of this Rule so that Parallel Operation with CUD’s Distribution System can occur (has occurred).

Interconnection Facilities: The electrical wires, switches and related equipment that are required in addition to the facilities required to provide electric Distribution Service to a Customer to allow Interconnection. Interconnection Facilities may be located on either side of the Point of Common Coupling as appropriate to their purpose and design. Interconnection Facilities may be integral to a Generating Facility or provided separately.

Interconnection Study: A study to establish the requirements for Interconnection of a Generating Facility with CUD’s Distribution System.

Island; Islanding: A condition on CUD’s Distribution System in which one or more Generating Facilities deliver power to Customers using a portion of CUD’s Distribution System that is electrically isolated from the remainder of CUD’s Distribution System.

Line Section: That portion of CUD’s Distribution System connected to a Customer bounded by automatic sectionalizing devices or the end of the distribution line.

Load Carrying Capability: The maximum electrical load that may be carried by a section of CUD’s Distribution System consistent with reliability and safety under the circumstances being evaluated.

Metering: The measurement of electrical power in kW and/or energy in kWh, and, if necessary, reactive power in kVAR at a point, and its display to CUD, as required by this Rule.

Metering Equipment: All equipment, hardware, software including meter cabinets, conduit, etc., that are necessary for Metering.

Momentary Parallel Operation: The interconnection of a Generating Facility to the Distribution System for one second (60 cycles) or less.

Nationally Recognized Testing Laboratory (NRTL): A laboratory accredited to perform the Certification Testing requirements under this Rule.

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Net Energy Metering: Metering for the receipt and delivery of electricity between the Producer and CUD pursuant to Section 2827, 2827.8, 2827.9, or 2827.10 of the Public Utilities Code.

Net Generation Output Metering: Metering of the net electrical power output in kW or energy in kWh, from a given Generating Facility. This may also be the measurement of the difference between the total electrical energy produced by a Generator and the electrical energy consumed by the auxiliary equipment necessary to operate the Generator. For a Generator with no Host Load and/or Public Utilities Code Section 218 Load (Section 218 Load), Metering that is located at the Point of Common Coupling. For a Generator with Host Load and/or Section 218 Load, Metering that is located at the Generator but after the point of auxiliary load(s) and prior to serving Host Load and/or Section 218 Load.

Net Nameplate Rating: The Gross Nameplate Rating minus the consumption of electrical power of a Generator or Generating Facility as designated by the manufacturer(s) of the Generator(s).

Network Service: More than one electrical feeder providing Distribution Service at a Point of Common Coupling.

Non-Export; Non-Exporting: Designed to prevent the transfer of electrical energy from the Generating Facility to CUD’s Distribution System.

Non-Islanding: Designed to detect and disconnect an Unintended Island with matched load and generation. Reliance solely on under/over voltage and frequency trip is not considered sufficient to qualify as Non-Islanding.

Parallel Operation: The simultaneous operation of a Generator with power delivered or received by CUD while Interconnected. For the purpose of this Rule, Parallel Operation includes only those Generating Facilities that are Interconnected with CUD’s Distribution System for more than 60 cycles (one second).

Paralleling Device: An electrical device, typically a circuit breaker, operating under the control of a synchronization function or by a qualified operator to connect an energized generator to an energized electric power system or two energized power systems to each other.

Periodic Test: A test performed on part or all of a Generating Facility/ Interconnection Facilities at pre-determined time or operational intervals to achieve one or more of the following: (1) Verify specific aspects of its performance; (2) Calibrate instrumentation; and (3) Verify and re-establish instrument or Protective Function set-points.

Point of Common Coupling (PCC): The transfer point for electricity between the electrical conductors of CUD and the electrical conductors of the Producer.

Point of Common Coupling Metering: Metering located at the Point of Common Coupling. This is the same Metering as Net Generation Metering for Generating Facilities with no Host Load and/or Section 218 Load.

Point of Interconnection: The electrical transfer point between a Generating Facility and CUD’s

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Distribution System. This may or may not be coincident with the Point of Common Coupling.

Producer: The entity that executes an Interconnection Agreement with CUD. The Producer may or may not own or operate the Generating Facility, but is responsible for the rights and obligations related to the Interconnection Agreement.

Production Test: A test performed on each device coming off the production line to verify certain aspects of its performance.

Protective Function(s): The equipment, hardware and/or software in a Generating Facility (whether discrete or integrated with other functions) whose purpose is to protect against Unsafe Operating Conditions.

Prudent Electrical Practices: Those practices, methods, and equipment, as changed from time to time, that are commonly used in prudent electrical engineering and operations to design and operate electric equipment lawfully and with safety, dependability, efficiency and economy.

Scheduled Operation Date: The date specified in the Interconnection Agreement when the Generating Facility is, by the Producer's estimate, expected to begin operation pursuant to this Rule.

Secondary Network: A network supplied by several primary feeders suitably interlaced through the area in order to achieve acceptable loading of the transformers under emergency conditions and to provide a system of extremely high service reliability. Secondary networks usually operate at 600 V or lower.

Section 218 Load: Electrical power that is supplied in compliance with California Public Utilities Code Section 218. Public Utilities Code Section 218 defines an “Electric Corporation” and provides conditions under which a transaction involving a Generating Facility would not classify a Producer as an Electric Corporation. These conditions relate to “over-the-fence” sale of electricity from a Generating Facility without using CUD’s Distribution System.

Short Circuit (Current) Contribution Ratio (SCCR): The ratio of the Generating Facility’s short circuit contribution to the short circuit contribution provided through CUD’s Distribution System for a three-phase fault at the high voltage side of the distribution transformer connecting the Generating Facility to CUD’s system.

Simplified Interconnection: Interconnection conforming to the Initial Review requirements under this Rule, as determined by Section I.

Single Line Diagram; Single Line Drawing: A schematic drawing, showing the major electric switchgear, Protective Function devices, wires, Generators, transformers and other devices, providing sufficient detail to communicate to a qualified engineer the essential design and safety of the system being considered.

Special Facilities: As defined in CUD’s Rules governing Special Facilities.

Starting Voltage Drop: The percentage voltage drop at a specified point resulting from In-rush

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Current. The Starting Voltage Drop can also be expressed in volts on a particular base voltage, (e.g., 6 volts on a 120-volt base, yielding a 5% drop).

Supplemental Review: A process wherein CUD further reviews an Application that fails one or more of the Initial Review Process steps. The Supplemental Review may result in one of the following: (a) approval of Interconnection; (b) approval of Interconnection with additional requirements; or (c) cost and schedule for an Interconnection Study.

System Integrity: The condition under which CUD’s Distribution System is deemed safe and can reliably perform its intended functions in accordance with the safety and reliability rules of CUD.

Telemetering: The electrical or electronic transmittal of Metering data in real-time to CUD.

Transfer Trip: A Protective Function that trips a Generating Facility remotely by means of an automated communications link controlled by CUD.

Type Test: A test performed on a sample of a particular model of a device to verify specific aspects of its design, construction and performance.

Unintended Island: The creation of an island, usually following a loss of a portion of CUD’s Distribution System, without the approval of CUD.

Unsafe Operating Conditions: Conditions that, if left uncorrected, could result in harm to personnel, damage to equipment, loss of System Integrity or operation outside pre-established parameters required by the Interconnection Agreement.

I. REVIEW PROCESS FOR APPLICATIONS TO INTERCONNECT GENERATION

FACILITIES

1. INTRODUCTION
This Review Process allows for rapid approval for the interconnection of those Generating Facilities that do not require an Interconnection Study. The review process includes a screening to determine if a Supplemental Review is required.

Note: Failure to pass any step of the review process means only that further review and/or studies are required before the Generating Facility can be approved for Interconnection with CUD’s Distribution System. It does not mean that the Generating Facility cannot be Interconnected. Though not explicitly covered in the Initial Review Process the Generating Facility shall be designed to meet all of the applicable requirements in Section D.

2. PURPOSE
The review determines the following:
a. If a Generating Facility qualifies for Simplified Interconnection;

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b. If a Generating Facility can be made to qualify for Interconnection with a Supplemental Review determining any additional requirements; or c. If an Interconnection Study is required, the cost estimate and schedule for performing the Interconnection Study.

3. REVIEW PROCESS DETAILS
Step 1: Is the PCC on a Networked Secondary System?
• If yes, the Generating Facility does not qualify for Simplified Interconnection. Perform Supplemental Review.
• If No, continue to next step.

Significance: Special consideration must be given to Generating Facilities proposed to be installed on networked secondary Distribution Systems because of the design and operational aspects of network protectors. There are no such considerations for radial Distribution Systems.

Step 2: Will power be exported across the PCC?
• If yes, the Generating Facility does not qualify for Simplified Interconnection.

Perform Supplemental Review.
• If No, the Generating Facility must incorporate one of the following four options:

Option 1 (“Reverse Power Protection”): To ensure that power is not exported across the PCC, a reverse power Protective Function may be provided. The default setting for this Protective Function, when used, shall be 0.1% (export) of the service transformer’s rating, with a maximum 2.0 second time delay.

Option 2 (“Minimum Power Protection”): To ensure that at least a minimum amount of power is imported across the PCC at all times (and therefore, that power is not exported), an under-power Protective Function may be provided. The default setting for this Protective Function, when used, shall be 5% (import) of the Generating Facility’s total Gross Nameplate Rating, with a maximum 2.0 second time delay.

Option 3 (“Certified Non-Islanding Protection”): To ensure that the incidental export of power across the PCC is limited to acceptable levels, this option, when used, requires that all of the following conditions be met: (a) the total Gross Nameplate Capacity of the Generating Facility must be no more than 25% of the nominal ampere rating of the Producer’s service equipment; (b) the total Gross Nameplate Capacity of the Generating Facility must be no more than 50% of the Producer’s service transformer capacity rating (this capacity requirement does not apply to customers taking primary service without an intervening transformer); and (c) the Generating Facility must be certified as Non-Islanding.

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The ampere rating of the Customer’s Service Equipment to be used in this evaluation will be that rating for which the customer’s utility service was originally sized or for which an upgrade has been approved. It is not the intent of this provision to allow increased export simply by increasing the size of the customer’s service panel, without separate approval for the resize.

Option 4 (“Relative Generating Facility Rating”): This option, when used, requires Net Nameplate Rating of the Generating Facility to be so small in comparison to its host facility’s minimum load, that the use of additional Protective Functions is not required to ensure that power will not be exported to CUD’s Distribution System. This option requires the Generating Facility capacity to be no greater than 50% of the Producer’s verifiable minimum Host Load over the past 12 months.

Significance:
1) If it can be ensured that the Generating Facility will not export power, CUD’s Distribution System does not need to be studied for Load-Carrying Capability or Generating Facility power flow effects on CUD voltage regulators. 2) This step permits the use of reverse-power or minimum-power relaying as a Non-Islanding Protective Function (Options 1, 2 and 3). 3) This step allows, under certain defined conditions, for Generating Facilities that incorporate Certified Non-Islanding protection to qualify for Simplified Step 3: Is the Interconnection Facilities Equipment Certified for the application or does the Interconnection Facilities Equipment have interim CUD approval? • If Yes, continue to next step.
• If No, the Generating Facility and/or Interconnection Facilities does not qualify or Simplified Interconnection. Perform Supplemental Review.

Interim approval allows the CUD to treat equipment that has not completed the Rule 21 certification requirements as having met the intent of this screen. Interim approval is granted, at CUD’s discretion, on a case by case basis, and approval for one Generating Facility does not guarantee approval for any other Generating Facility Significance: If the Generating Facility and/or Interconnection Facilities has been Certified or previously approved by CUD, CUD does not need to repeat its full review and/or test of the Generating and/or Interconnection Facilities’ Protective Functions.

Site Commissioning Testing may still be required to ensure that the Protective Functions are working properly.

Certification indicates that the criteria in Section J, as appropriate, have been tested and verified.

Step 4: Is the aggregate Generating Facility capacity on the Line Section less than 15%

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of Line Section peak load?
• If Yes, continue to next step.
• If No, the Generating Facility does not qualify for Simplified Interconnection.

Perform Supplemental Review to determine cumulative impact online Section.

Significance:
1) Low penetration of Generating Facility installations will have a minimal impact on the operation and load restoration efforts of CUD’s Distribution System. 2) The operating requirements for a high penetration of Generating Facilities may be different since the impact on CUD’s Distribution System will no longer be minimal, therefore requiring additional study or controls.

Step 5: Is the Starting Voltage Drop within acceptable limits? • If Yes, continue to next step.
• If No, the Generating Facility does not qualify for Simplified Interconnection.

Perform Supplemental Review.

Note: This Step only applies to Generating Facilities that start by motoring the Generator(s).

CUD has two options in determining whether Starting Voltage Drop is acceptable. The option to be used is at CUD’s discretion:

Option 1: CUD may determine that the Generating Facility’s starting In-rush Current is equal to or less than the continuous ampere rating of the customer’s service equipment.

Option 2: CUD may determine the impedances of the service distribution transformer (if present) and the secondary conductors to Customer’s service equipment and perform a voltage drop calculation. Alternatively, CUD may use tables or nomographs to determine the voltage drop. Voltage drops caused by starting a Generator as a motor must be less than 2.5% for primary interconnections and 5% for secondary interconnections.

Significance:
1) This step addresses potential voltage fluctuation problems that may be caused by Generators that start by motoring.
2) When starting, Generating Facilities should have minimal impact on the service voltage to other CUD Customers.
3) Passing this step does not relieve the Producer from ensuring that its

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Generating Facility complies with the flicker requirements of this Rule, Section D.2.d.

Step 6: Is the Gross Nameplate Rating of the Generating Facility 11 kVA or less? • If Yes, the Generating Facility qualifies for Simplified Interconnection. Skip remaining steps.
• If No, continue to next step.

Significance:

The Generating Facility will have a minimal impact on fault current levels and any potential line overvoltage’s from loss of CUD’s Distribution System neutral grounding.

Step 7: Is the Short Circuit Current Contribution Ratio within acceptable limits? • If Yes, continue to next step.
• If No, the Generating Facility does not qualify for Simplified Interconnection. Perform Supplemental Review.

The Short Circuit Current Contribution Ratio Screen consists of two criteria; both of which must be met when applicable:
1) When measured at primary side (high side) of a Dedicated Distribution Transformer serving a Generating Facility, the sum of the Short Circuit Contribution Ratios of all generating facilities connected to CUD’s Distribution System circuit that serves the Generating Facility must be less than or equal to 0.1, and
2) When measured at the secondary side (low side) of a shared distribution transformer, the short circuit contribution of the proposed Generating Facility must be less than or equal to 2.5% of the interrupting rating of the Producer’s Service Equipment.

Significance:

If the Generating Facility passes this screen it can be expected that it will have no significant impact on CUD’s Distribution System’s short circuit duty, fault detection sensitivity, relay coordination or fuse-saving schemes.

Step 8: Is the Line Configuration compatible with the Interconnection type? • If Yes, the Generating Facility qualifies for Simplified Interconnection. • If No, then the Generating Facility does not qualify for Simplified Interconnection. Perform Supplemental Review. Identify primary distribution line configuration that will serve the Generating Facility. Based on the type of

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Interconnection to be used for the Generating Facility, determine from the Table I.1 if the proposed Generating Facility passes the step.

Table I.1
Primary Distribution
Line Type Configuration
Type of Interconnection to
be made to Primary
Distribution Line
Results/Criteria
Three-phase, three wire Any type Pass Step
Three-phase, four wire Single-phase,
line-to neutral Pass Step
Three-phase, four wire (For any line that has such a
section OR mixed three wire and four wire)
All others To pass, aggregate GF
Nameplate Rating must be
less than or equal to 10%
of Line Section peak load
Significance: If the primary distribution line serving the Generating Facility is of a “three-wire” configuration, or if the Generating Facility’s distribution transformer is single-phase and connected in a line-to-neutral configuration, then there is no concern about overvoltages to CUD’s, or other Customer’s equipment caused by loss of system neutral grounding during the operating time of the Non-Islanding Protective Function.

J. CERTIFICATION AND TESTING CRITERIA

1. INTRODUCTION
This Section describes the test procedures and requirements for equipment used for the Interconnection of Generating Facilities to CUD’s Distribution System. Included are Type Testing, Production Testing, Commissioning Testing and Periodic Testing. The procedures listed rely heavily on those described in appropriate Underwriters Laboratory (UL), Institute of Electrical and Electronic Engineers (IEEE), and International Electrotechnical Commission (IEC) documents—most notably UL 1741 and IEEE 929, as well as the testing described in May 1999 New York State Public Services Commission Standardized Interconnection Requirements. As noted in Section A, this rule has been revised to be consistent with ANSI/IEEE 1547-2003 Standard for Interconnecting Distributed Resources with Electric Power Systems.

The tests described here, together with the technical requirements in Section D of this Rule, are intended to provide assurance that the Generating Facility’s equipment will not adversely affect CUD’s Distribution System and that a Generating Facility will cease providing power to CUD’s Distribution System under abnormal conditions. The tests were developed assuming a low level of Generating Facility penetration or number of connections to CUD’s Distribution System. At high levels of Generating Facility penetration, additional requirements and corresponding test procedures may need to be

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defined.

Section J also provides criteria for “Certifying” Generators or inverters. Once a Generator or inverter has been Certified per this Rule, it may be considered suitable for Interconnection with CUD’s Distribution System. Subject to the exceptions described in Section J, CUD will not repeat the design review or require retesting of such Certified Equipment. It should be noted that the Certification process is intended to facilitate Generating Facility Interconnections. Certification is not a prerequisite to interconnect a Generating Facility.

The revisions made to this rule relative to IEEE 1547-2003 have resulted in changes in set points, test criteria, test procedures, and other requirements that will impact previously certified or listed equipment as well as equipment currently under evaluation. These changes were made to provide consistency with IEEE 1547.

Equipment that is certified or that has been submitted to a Nationally Recognized Testing Laboratory (NRTL) for testing prior to the adoption of the revised Underwriters Laboratories (UL) 1741 titled Inverters, Converters, Controllers and Interconnection Systems Equipment for use with Distributed Energy Resources and that subsequently meet the provisions Rule 21 certification requirements will continue to be accepted as Certified Equipment for Interconnection Applications submitted through May 7, 2007, the effective date of the revised UL 1741. [this change will be incorporated by Advice Letter in Dec. 2005]

2. CERTIFIED AND NON-CERTIFIED INTERCONNECTION EQUIPMENT a. Certified Equipment
Equipment tested and approved (e.g., “Listed”) by an accredited NRTL as having met both the Type Testing and Production Testing requirements described in this document is considered to be Certified Equipment for purposes of Interconnection with CUD’s Distribution System. Certification may apply to either a pre-packaged system or an assembly of components that address the necessary functions. Type Testing may be done in the manufactures’ factory or test laboratory, or in the field. At the discretion of the testing laboratory, fieldcertification may apply only to the particular installation tested. In such cases, some or all of the tests may need to be repeated at other installations.

When equipment is certified by a NRTL, the NRTL shall provide to the manufacturer, at a minimum, a Certificate with the following information for each device:

Administrative:
1) The effective date of Certification or applicable serial number (range or first in series), and/or other proof that Certification is current; 2) Equipment model number(s) of the Certified Equipment;

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3) The software version utilized in the equipment, if applicable; 4) Test procedures specified (including date or revision number); and 5) Laboratory accreditation (by whom and to what standard).

Technical (as appropriate):
1) Device ratings (kW, kVA, Volts, Amps, etc.);
2) Maximum available fault current in Amps;
3) In-rush Current in Amps;
4) Trip points, if factory set (trip value and timing); 5) Trip point and timing ranges for adjustable settings; 6) Nominal power factor or range if adjustable;
7) If the equipment is Certified for Non-Exporting and the method used (reverse power or under power); and
8) If the equipment is Certified Non-Islanding.

It is the responsibility of the equipment manufacturer to ensure that Certification information is made publicly available by the manufacturer, the testing laboratory or by a third party.
b. Non-Certified Equipment
For non-Certified Equipment, some or all of the tests described in this Rule may be required by CUD for each Generating Facility and/or Interconnection Facilities. The manufacturer or a laboratory acceptable to CUD may perform these tests. Test results for Non-Certified Equipment must be submitted to CUD for the Supplemental Review. Approval by CUD for equipment used in a particular Generating Facility and/or Interconnection Facilities does not guarantee CUD’s approval for use in other Generating Facility and/or Interconnection Facilities.

3. TYPE TESTING
a. Type Tests and Criteria for Interconnection Equipment Certification. Type Testing provides a basis for determining that equipment meets the specifications for being designated as Certified Equipment under this Rule. The requirements described in this Section cover only issues related to Interconnection and are not

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intended to address equipment safety or other issues.

Table J.1. defines the test criteria by Generator or inverter technology. While UL 17411 was written specifically for inverters, the requirements are readily adaptable to synchronous Generators, induction Generators, as well as single/multi-function controllers and protection relays. Until a universal test standard is developed, CUD or NRTL shall adapt the procedures referenced in Table J.1 as appropriate and necessary for a Generating Facility and/or Interconnection Facilities or associated equipment performance and its control and Protective Functions. The tests shall be performed in the sequence shown in Table J.2 below.

Table J.1 Type Tests and Requirements for Interconnection Equipment Certification Type Test Reference (1) Inverter Synchronous
Generator
Induction
Generator
Utility Interaction UL 1741 – 39 X X X
DC Isolation UL 1741 – 40.1 X - -
Simulated PV Array (Input)
Requirements
UL 1741 – 41.2 X - -
Dielectric Voltage Withstand UL 1741 – 44 X X X
Power Factor UL 1741 – 45.2.2 X X X
Harmonic Distortion UL 1741 – 45.4 X X X
DC Injection UL 1741 – 45.5 X - -
Utility Voltage and Frequency
Variation
UL 1741 – 46.2 X X X
Reset Delay UL 1741 – 46.2.3 X X X
Loss of Control Circuit UL 1741 – 46.4 X X X
Short Circuit UL 1741 – 47.3 X X X
Load Transfer UL 1741 – 47.7 X X X
Surge Withstand Capability J.3.e X X X
Anti-Islanding J.3.b (2) (2) (2)
Non-Export J.3.c (3) (3) (3)
In-rush Current J.3.d - - (4)
Synchronization J.3.f (5) X (5)
Table Notes: (1) References are to section numbers in either UL 1741 (Inverters, Converters and Charge Controllers for use in Independent Power Systems) or this Rule. References in UL 1741 to “photovoltaics” or “inverter” may have to be adapted to the other technologies by the testing laboratory to appropriately apply in the tests to other technologies. (2) Required only if Non-Islanding designation
(3) Required only if Non-Export designation is desired. (4) Required for Generators that use CUD power to motor to speed. (5) Required for all self-excited induction Generators as well as Inverters that operate as voltage sources when connected to CUD’s Distribution System.

X = Required , - = Not Required

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Table J.2 Type Tests Sequence for Interconnection Equipment Certification Test No. Type Test
1 Utility Voltage and Frequency Variation
2 Synchronization
3 Surge Withstand Capability
4 Utility Voltage and Frequency Variation
5 Synchronization
6 Other Required and Optional Tests
Tests 1, 2, and 3, must be done first and in the order shown.

Tests 4 and on follow in order convenient to the test agency. c. Anti-Islanding Test:

Devices that pass the Anti-Islanding test procedure described in UL 1741 Section 46.3 will be considered Non-Islanding for the purposes of these interconnection requirements.

The test is required only for devices for which a Certified Non-Islanding designation is desired.
c. Non-Export Test:

Equipment that passes the Non-Export test procedure described in Section J.7.a. will be considered Non-Exporting for the purposes of these Interconnection requirements. This test is required only for equipment for which a Certified Non-Export designation is desired.
d. In-rush Current Test:

Generation equipment that utilizes CUD power to motor up to speed will be tested using the procedure defined in Section J.7.b. to determine the maximum current drawn during this startup process. The resulting In-rush Current is used to estimate the Starting Voltage Drop.
e. Surge Withstand Capability Test:

The interconnection equipment shall be tested for the surge withstand requirement in D.1.c in all normal operating modes in accordance with IEEE Std C62.45-2002 for equipment rated less than 1000 V to confirm that the surge withstand capability is met by using the selected test level(s) from IEEE Std C62.41.2-2002. Interconnection equipment rated greater than 1000 V shall be tested in accordance with manufacturer or system integrator designated applicable standards. For interconnection equipment signal and control circuits, use IEEE Std C37.90.1-2002. These tests shall confirm the equipment did not fail, did not misoperate, and did not provide misinformation (IEEE1547-5.1.3.2). The location/exposure category for which the equipment has been tested shall be clearly marked on the equipment label or in the equipment documentation. External surge protection may be used to protect the equipment in harsher location/exposure categories.
f. Synchronization Test:

This test is applied to synchronous Generators, self-excited induction generators, and inverters capable of operating as voltage-source while connected to CUD’s Distribution System. The test is also applied to the resynchronization Function (transition from

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stand-alone to parallel operation) on equipment that provides such functionality. This test may not need to be performed on both the synchronization and re-synchronization functions if the manufacturers can verify to the satisfaction of the testing organization that monitoring and controls hardware and software are common to both functions. This test is not necessary for induction generators or current-source inverters. Instead, the lnrush Current test Section J.3.d shall be applied to those generators.

This test shall demonstrate that at the moment of the paralleling-device closure, all three synchronization parameters in Table J.3 are within the stated limits. This test shall also demonstrate that if any of the parameters are outside of the limits stated in the table, the paralleling-device shall not close (IEEE 1547- 5.1.2A). The test will start with only one of the three parameters: (1) voltage difference between Generating Facility and CUD’s Distribution System; (2) frequency difference; or (3) phase angle outside of the synchronization specification. Verify that the Generating Facility is brought within specification prior to synchronization. Repeat the test five times for each of the three parameters. For manual synchronization with synch check or manual control with auto synchronization, the test must verify that paralleling does not occur until the parameters are brought within specifications.

Table J.3. Synchronization Parameter Limits [1] Aggregate Rating Aggregate Rating
of Generator Units
(kVA)
Frequency
Difference
(Δf, Hz)
Voltage
Difference
(ΔV, %)
Phase Angle
Difference
0-500
> 500-1,500
> 1,500-10,000

0.3 0.2

0.1 10
5 3
20 15
10 [1] – IEEE 1547-5.1.1B
g. Paralleling Device Withstand Test
The di-electric voltage withstand test specified in Section J.1 shall be performed on the paralleling device to ensure compliance with those requirements specified in Section D.1.c (IEEE 1547-5.1.3.3).

4. Production Testing:

As a minimum, each interconnection system shall be subjected to the Utility Voltage and Frequency Variation Test procedure described in UL1741 under Manufacturing and Production Tests, Section 68 and the Synchronization test specified in Section J.3.f Interconnection systems with adjustable set points shall be tested at a single set of set points as specified by the manufacturer. This test may be performed in the factory or as part of a Commissioning Test (Section J.5.).

5. Commissioning Testing:
a. Commissioning Testing, where required, will be performed on-site to verify protective settings and functionality. Upon initial Parallel Operation of a Generating Facility, or

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any time interface hardware or software is changed that may affect the functions listed below, a Commissioning Test must be performed. An individual qualified in testing protective equipment (professional engineer, factory–certified technician, or licensed electrician with experience in testing protective equipment) must perform Commissioning Testing in accordance with the manufacturer’s recommended test procedure to verify the settings and requirements per this Rule.

CUD may require written Commissioning test procedure be submitted to MVU at least 10 working days prior to the performance of the Commissioning Test. CUD has the right to witness Commissioning Test, CUD may also require written certification by the installer describing which tests were performed and their results. Protective Functions to be tested during commissioning, particularly with respect to non-Certified equipment, may consist of the following:
(1) Over and under voltage
(2) Over and under frequency
(3) Anti-Islanding function (if applicable)
(4) Non-Exporting function (if applicable)
(5) Inability to energize dead line
(6) Time delay on restart after utility source is stable (7) Utility system fault detection (if used)
(8) Synchronizing controls (if applicable)
(9) Other Interconnection Protective Functions that may be required as part of the Interconnection Agreement
Commissioning Test shall include visual inspections of the interconnection equipment and protective settings to confirm compliance with the interconnection requirements. b. Other checks and tests that may need to be performed include:
(1) Verifying final Protective Function settings
(2) Trip test (J.5.f)
(3) In-service tests (J.5.g)
c. Certified Equipment
Generating Facilities qualifying for Simplified Interconnection incorporate Certified Equipment that have, at a minimum, passed the Type Tests and Production Tests described in this Rule and are judged to have little or no potential impact on CUD’s Distribution System. For such Generating Facilities, it is necessary to perform only the following tests:
(1) Protective Function settings that have been changed after Production Testing will require field verification. Tests shall be performed using injected secondary frequencies, voltages and currents, applied waveforms, at a test connection using a Generator to simulate abnormal utility voltage or frequency, or varying the set points to show that the device trips at the measured (actual) utility voltage or frequency.

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(2) The Non-Islanding function shall be checked by operating a load break disconnect switch to verify the Interconnection equipment ceases to energize CUD’s Distribution System and does not re-energize it for the required time delay after the switch is closed. (3) The Non-Exporting function shall be checked using secondary injection techniques.

This function may also be tested by adjusting the Generating Facility output and local loads to verify that the applicable Non-Exporting criteria (i.e., reverse power or underpower) are met.

The Supplemental Review or an Interconnection Study may impose additional components or additional testing.
d. Non-Certified Equipment
Non-certified Equipment shall be subjected to the appropriate tests described in Type Testing (Section J.3.) as well as those described in Certified Equipment Commissioning Tests (Section J.5.c.). With CUD’s approval, these tests may be performed in the factory, in the field as part of commissioning, or a combination of both. CUD, at its discretion, may also approve a reduced set of tests for a particular Generating Facility or, for example, if it determines it has sufficient experience with the equipment. e. Verification of Settings
At the completion of Commission testing, the Producer shall confirm all devices are set to CUD-approved settings. Verification shall be documented in the Commissioning Test Certification.
f. Trip Tests:

Interconnection Protective Functions and devices (e.g. reverse power relays) that have not previously been tested as part of the Interconnection Facilities with their associated interrupting devices (e.g. contactor or circuit breaker) shall be trip tested during commissioning. The trip test shall be adequate to prove that the associated interrupting devices open when the protective devices operate. Interlocking circuits between Protective Function devices or between interrupting devices shall be similarly tested unless they are part of a system that has been tested and approved during manufacturing.
g. In-service Tests:

Interconnection Protective Functions and devices that have not previously been tested as part of the Interconnection Facilities with their associated instrument transformers or that are wired in the field shall be given an in-service test during commissioning. This test will verify proper wiring, polarity, CT/PT ratios, and proper operation of the measuring circuits. The in-service test shall be made with the power system energized and carrying a known level of current. A measurement shall be made of the magnitude and phase angle of each Alternating Current (AC) voltage and current connected to the protective device and the results compared to expected values. For protective devices with built-in Metering Functions that report current and voltage magnitudes and phase

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angles, or magnitudes of current, voltage, and real and reactive power, the metered values may be used for in-service testing. Otherwise, portable ammeters, voltmeters, and phase-angle meters shall be used.

6. Periodic Testing:

Periodic Testing of Interconnection-related Protective Functions shall be performed as specified by the manufacturer, or at least every four years. All Periodic Tests prescribed by the manufacturer shall be performed. The Producer shall maintain Periodic Test reports or a log for inspection by CUD. Periodic Testing conforming to CUD test intervals for the particular Line Section may be specified by CUD under special circumstances, such as high fire hazard areas.

Batteries used to activate any Protective Function shall be checked and logged once per month for proper voltage.

Once every four years, the battery must be either replaced or a discharge test performed.

7. Type Testing Procedures Not Defined in Other Standards:

This Section describes the additional Type Tests necessary to qualify a device as Certified under this Rule. These Type Tests are not contained in Underwriters Laboratories UL 1741 Standard Inverters, Converters and Controllers for Use in Independent Power Systems, or other referenced standards.
a. Non-Exporting Test Procedures
The Non-Exporting test is intended to verify the operation of relays, controllers and inverters designed to limit the export of power and certify the equipment as meeting the requirements of Screen 2, Options 1 and 2, of the review process.

Tests are provided for discrete relay packages and for controllers and inverters with the intended Functions integrated.
(1) Discrete Reverse Power Relay Test:

This version of the Non-Exporting test procedure is intended for discrete reverse power and underpower relay packages provided to meet the requirements of Options 1 and 2 of Screen 2. It should be understood that in the reverse power application, the relay will provide a trip output with power flowing in the export (toward CUD’s Distribution System) direction.

Step 1: Power Flow Test at Minimum, Midpoint and Maximum Pickup Level Settings
Determine the corresponding secondary pickup current for the desired export power flow of 0.5 secondary watts (the minimum pickup setting, assumes 5 amp and 120V CT/PT secondary). Apply nominal voltage with minimum current setting at zero (0) degrees phase angle in the trip direction. Increase the current to pickup level. Observe the relay’s (LCD or computer display) indication of power values. Note the indicated power level at which the relay trips. The power indication should be within 2% of the expected power. For relays with adjustable settings, repeat this test at the midpoint, and maximum settings.

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Repeat at phase angles of 90, 180 and 270 degrees and verify that the relay does not operate (measured watts will be zero or negative).

Step 2: Leading Power Factor Test
Apply rated voltage with a minimum pickup current setting (calculated value for system application) and apply a leading power factor load current in the non-trip direction (current lagging voltage by 135 degrees). Increase the current to relay rated current and verify that the relay does not operate. For relays with adjustable settings, this test should be repeated at the minimum, midpoint, and maximum settings.

Step 3: Minimum Power Factor Test
At nominal voltage and with the minimum pickup (or ranges) determined in Step 1, adjust the current phase angle to 84 or 276 degrees. Increase the current level to pickup (about 10 times higher than at 0 degrees) and verify that the relay operates. Repeat for phase angles of 90, 180 and 270 degrees and verify that the relay does not operate.

Step 4: Negative Sequence Voltage Test
Using the pickup settings determined in Step 1, apply rated relay voltage and current at 180 degrees from tripping direction, to simulate normal load conditions (for three-phase relays, use Ia at 180, Ib at 60 and Ic at 300 degrees).

Remove phase-1 voltage and observe that the relay does not operate. Repeat for phases-2 and 3.

Step 5: Load Current Test
Using the pickup settings determined in Step 1, apply rated voltage and current at 180 degrees from the tripping direction, to simulate normal load conditions (use Ia at 180, Ib at 300 and Ic at 60 degrees). Observe that the relay does not operate.

Step 6: Unbalanced Fault Test
Using the pickup settings determined in Step 1, apply rated voltage and 2 times rated current, to simulate an unbalanced fault in the non-trip direction (use Va at 0 degrees, Vb and Vc at 180 degrees, Ia at 180 degrees, Ib at 0 degrees, and Ic at 180 degrees). Observe that the relay, especially single phase, does operate properly.

Step 7: Time Delay Settings Test
Apply Step 1 settings and set time delay to minimum setting. Adjust the current source to the appropriate level to determine operating time and compare against

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calculated values. Verify that the timer stops when the relay trips. Repeat at midpoint and maximum delay settings.

Step 8: Dielectric Test
Perform the test described in ICUD 414 using 2 kV RMS for 1 minute.

Step 9: Surge Withstand Test
Perform the surge withstand test described in IEEE C37.90.1.1989 or the surge withstand capability test described in J.3.e.
(2) Discrete Underpower Relay Test
This version of the Non-Exporting test procedure is intended for discrete underpower relay packages and meets the requirements of Option 2 of Screen 2. A trip output will be provided when import power (toward the Producer’s load) drops below the specified level.

Note: For an underpower relay, pickup is defined as the highest power level at which the relay indicates that the power is less than the set level.

Step 1: Power Flow Test at Minimum, Midpoint and Maximum Pickup Level Settings
Determine the corresponding secondary pickup current for the desired power flow pickup level of 5% of peak load minimum pickup setting. Apply rated voltage and current at 0 (zero) degrees phase angle in the direction of normal load current. Decrease the current to pickup level. Observe the relay’s (LCD or computer display) indication of power values. Note the indicated power level at which the relay trips. The power indication should be within 2% of the expected power. For relays with adjustable settings, repeat the test at the midpoint, and maximum settings. Repeat at phase angles of 90, 180 and 270 degrees and verify that the relay operates (measured watts will be zero or negative).

Step 2: Leading Power Factor Test
Using the pickup current setting determined in Step 1, apply rated voltage and rated leading power factor load current in the normal load direction (current leading voltage by 45 degrees). Decrease the current to 145% of the pickup level determined in Step 1 and verify that the relay does not operate. For relays with adjustable settings, repeat the test at the minimum, midpoint, and maximum settings.

Step 3: Minimum Power Factor Test
At nominal voltage and with the minimum pickup (or ranges) determined in Step 1, adjust the current phase angle to 84 or 276 degrees. Decrease the current level to pickup (about 10% of the value at 0 degrees) and verify that the relay operates. Repeat for

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phase angles 90, 180 and 270 degrees and verify that the relay operates for any current less than rated current.

Step 4: Negative Sequence Voltage Test
Using the pickup settings determined in Step 1, apply rated relay voltage and 25% of rated current in the normal load direction, to simulate light load conditions. Remove phase 1 voltage and observe that the relay does not operate. Repeat for Phases-2 and 3.

Step 5: Unbalanced Fault Test
Using the pickup settings determined in Step 1, apply rated voltage and two times rated current, to simulate an unbalanced fault in the normal load direction (use Va at 0 degrees, Vb and Vc at 180 degrees, Ia at 0 degrees, Ib at 180 degrees, and Ic at 0 degrees). Observe that the relay (especially single-phase types) operates properly.

Step 6: Time Delay Settings Test
Apply Step 1 settings and set time delay to minimum setting. Adjust the current source to the appropriate level to determine operating time and compare against calculated values. Verify that the timer stops when the relay trips. Repeat at midpoint and maximum delay settings.

Step 7: Dielectric Test
Perform the test described in IEC 414 using 2 kV RMS for 1 minute.

Step 8: Surge Withstand Test
Perform the surge withstand test described in IEEE C37.90.1.1989 or the surge withstand test described in Section J.3.e.
(3) Tests for Inverters and Controllers with Integrated Functions Inverters and controllers designed to provide reverse or underpower functions shall be tested to certify the intended operation of this function. Two methods are acceptable:

Method 1: If the inverter or controller utilizes external current/voltage measurement to determine the reverse or underpower condition, then the inverter or controller shall be functionally tested by application of appropriate secondary currents and potentials as described in the Discrete Reverse Power Relay Test, Section J.7.a.(1) of this Rule.

Method 2: If external secondary current or voltage signals are not used, then unit-specific tests must be conducted to verify that power cannot be exported across the PCC for a period exceeding two seconds. These may be factory tests, if the measurement and control points are integral to the unit, or they may be performed in the field.

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(4) In-rush Current Test Procedures:

This test will determine the maximum In-rush Current drawn by the Generator. (1) Locked-Rotor Method
Use the test procedure defined in NEMA MG-1 (manufacturer’s data is acceptable if available).
(2) Start-up Method
Install and setup the Generating Facility equipment as specified by the manufacturer.

Using a calibrated oscilloscope or data acquisition equipment with appropriate speed and accuracy, measure the current draw at the Point of Interconnection as the Generating Facility starts up and parallels with CUD’s Distribution System. Startup shall follow the normal, manufacturer-specified procedure. Sufficient time and current resolution and accuracy shall be used to capture the maximum current draw within 5%.

In-rush Current is defined as the maximum current draw from CUD during the startup process, using a 10-cycle moving average. During the test, the utility source, real or simulated, must be capable of maintaining voltage within +/- 5% of rated at the connection to the unit under test. Repeat this test five times. Report the highest 10-cycle current as the In-rush Current. A graphical representation of the time-current characteristic along with the certified In-rush Current must be included in the test report and made available to CUD.

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Rule 21A
Applicability
The former CUD Net Energy Metering/Interconnection Agreement has been replaced by Rule 21A.

This rule applies to all interconnections between CUD and the generation Producer providing for the Interconnection of a Generating Facility that gives certain rights and obligations to effect or end Interconnection.

Applicable to Customer-Generators, as defined in Section 2827 of the California Public Utilities Code, operating a renewable electrical generation facility, as therein defined, located on the customer’s owned, leased, or rented premises, is a vendor/contractor owned PV system that is leased or rented (includes a purchase power agreement) to a CUD electric customer or a customer owned system that is intended primarily to offset part or all of the customer’s own electrical requirements and which is interconnected and operates in parallel with CUD’s power system as authorized by CUD.

CUD shall make a determination regarding the appropriate assigned schedule for the applicant based upon available capacity. If the applicant falls within five percent (5%) of CUD’s maximum coincident peak demand in the prior fiscal year “Net Energy Metering (NEM) Capacity Value”, the applicant shall fall under the NEM schedule. If the applicant falls outside of the NEM Capacity Value, they shall be assigned to the Eligible Renewable Generation (ERG) schedule.

Territory
Within the entire territory served by City of Corona, Utilities Department.

Net Energy Metering (NEM) Customers Terms and Conditions Special Conditions

1. All special conditions related to billing and metering shall be addressed in the Electric Energy Schedule of User/Service fees under NEM.

2. CUD shall retain any net surplus energy generated by the NEM customer, including any associated environmental attributes or renewable energy credits (“REC”).

3. To be eligible for service under this Schedule, generating facilities must meet all applicable safety and performance standards established by the National Electrical Code, the Institute of Electrical and Electronics Engineers, and accredited testing laboratories such as Underwriters Laboratories and, where applicable, rules regarding safety and reliability (i.e., CUD’s Electric Rule 21). All generating facilities must have a warranty of at least 10 years for all equipment and the associated installation from the system provider (not from CUD). All major solar system components (including PV panels and other generation equipment, inverters and meters) must be on the verified equipment list maintained by the CEC. Any other equipment, as determined by CUD, must be verified as having safety certification from a Nationally Recognized Testing Laboratory.

4. To be eligible for service under this Schedule, the customer’s generating facilities must be sized to offset part or all of the customer’s own electrical requirements and cannot be oversized. This

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means that the estimated output of the generating facility, using the CEC-AC nameplate rating for inverter-based generating facilities must not exceed the customer’s previous annual usage in kWh. In the event that there is less than 12 months of previous recorded usage data, the standard of 2 watts per square foot of the premises will apply.

5. Customers seeking to interconnect their generating facilities for the purpose of receiving service under this Schedule are subject to the interconnection requirements and interconnection cost responsibility provisions as established in CUD’s Electric Rule 21.

6. A new customer of record who owns, rents, or leases a premise that includes a generating facility that was approved by CUD for parallel operation prior to the new customer moving in and/or taking electric service with CUD will take service under this Schedule as long as the requirements of this Schedule are met. This provision also applies to premises where the developer/contractor establishes the interconnection.

7. Existing generating facilities currently under Schedule NEM that are modified such that: (1) the generating capacity or output increases by 10% or more; or (2) adding battery storage will be placed under Schedule ERG.

8. Existing customers under Schedule NEM can request to be placed under Schedule ERG at any time; the customer’s account will be trued up at the time of the request. This means that any outstanding balance due or credit due will be applied to the next regular billing.

Eligible Renewable Generation (ERG) Customers Terms and Conditions Special Conditions

1. All special conditions related to billing and metering shall be addressed in the Electric Energy Schedule of User/Service fees under ERG.

2. CUD shall retain any net surplus energy generated by the ERG customer, including any associated environmental attributes or renewable energy credits (“REC”).

3. To be eligible for service under this Schedule, generating facilities must meet all applicable safety and performance standards established by the National Electrical Code, the Institute of Electrical and Electronics Engineers, and accredited testing laboratories such as Underwriters Laboratories and, where applicable, rules regarding safety and reliability (i.e., CUD’s Electric Rule 21). All generating facilities must have a warranty of at least 10 years for all equipment and the associated installation from the system provider (not from CUD). All major solar system components (including PV panels and other generation equipment, inverters and meters) must be on the verified equipment list maintained by the CEC. Any other equipment, as determined by CUD, must be verified as having safety certification from a Nationally Recognized Testing Laboratory.

4. To be eligible for service under this Schedule, the customer’s generating facilities must be sized to offset part or all of the customer’s own electrical requirements and cannot be oversized. This means that the estimated output of the generating facility, using the CEC-AC nameplate rating

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for inverter-based generating facilities must not exceed the customer’s previous annual usage in kWh. In the event that there is less than 12 months of previous recorded usage data, the standard of 2 watts per square foot of the premises will apply.

5. Customers seeking to interconnect their generating facilities for the purpose of receiving service under this Schedule are subject to the interconnection requirements and interconnection cost responsibility provisions as established in CUD’s Electric Rule 21.

6. A new customer of record who owns, rents, or leases a premise that includes a generating facility that was approved by CUD for parallel operation prior to the new customer moving in and/or taking electric service with CUD will take service under this Schedule as long as the requirements of this Schedule are met. This provision also applies to premises where the developer/contractor establishes the interconnection.

7. Existing generating facilities currently under Schedule NEM that are modified such that: (1) the generating capacity or output increases by 10% or more; or (2) adding battery storage will be placed under Schedule ERG.

Solar or Wind Generating Facility

1. Operating Option

1. Customer has elected to construct, design, install, operate, and maintain the Facility in a manner consistent with the normal and safe operation of the electrical distribution system owned and operated by CUD. The Facility is intended primarily to provide part or all of the Customer’s own electrical energy requirements. If the facility is within the service territory of CUD, then by that fact the Customer understands, accepts, and agrees that connection and operation of the Customer’s Facility shall be subject to the terms and conditions set forth in in CUD’s Electric Service Rules (the “Rules”).

2. Pursuant to Electric Service Rule No. 21 and Rule 21A, based on facility type and size, an Interconnection Fee may be required.

2. Credits for Net Energy

1. NEM Customers. NEM customer is eligible to receive credits for energy if Customer’s monthly energy generated by the Facility exceeds Customer’s monthly energy requirements, calculated by the “Net Metering.” Net Metering uses a non-demand, time differentiated meter or meters to measure the difference between the energy supplied by CUD and the energy generated by the Facility and supplied to CUD. Net metering account billing options, net energy carryover rules and restrictions, and energy costs are controlled by CUD’s Net Metering Schedule in effect at the time of Customer’s start of service.

2. ERG Customers. ERG Customer is eligible to receive credits for any energy generated by the Customer and delivered to the grid. Electricity delivered from CUD and consumed by the Customer shall be billed monthly on the Customer’s otherwise applicable rate.

Electricity supplied by the Renewable Electrical Generation Facility that is utilized onPage 1812 of 1895

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site by the Customer will not be measured, charged, or credited by CUD. ERG account billing options and energy costs are controlled by CUD’s Eligible Renewable Generation Schedule in effect at the time of Customer’s start of service.

3. Interruption or Reduction of Deliveries

1. CUD shall not be obligated to accept, and CUD may require Customer to interrupt or reduce, deliveries of energy to CUD: (a) when necessary in order to construct, install, maintain, repair, replace, remove, investigate, or inspect any of CUD’s equipment or part of the CUD system; or (b) if CUD determines that curtailment, interruption, or reduction of receipt of energy from Customer’s Facility is necessary because of emergencies, forced outages, force majeure, or compliance with prudent electrical practices.

2. Notwithstanding any other provision of this Rule, if at any time CUD, in its sole discretion, determines that either (a)the Facility may endanger CUD personnel or members of the general public, or (b) the continued operation of Customer’s Facility may impair the integrity of CUD’s electric distribution system, CUD shall have the right to disconnect Customer’s Facility from CUD’s electric distribution system. Customer’s Facility shall remain disconnected until such time as CUD is satisfied that the condition(s) referenced in (a) or (b) of this paragraph have been corrected, and CUD shall not be obligated to compensate Customer for any loss of use of generation or energy during any and all periods of such disconnection.

4. Interconnection

1. Customer shall deliver energy from the Facility to CUD at CUD’s meter.

2. Customer, and not CUD, shall be solely responsible for all legal and financial obligations arising from the construction, installation, design, operation, and maintenance of the Facility in accordance with all applicable laws and regulations.

3. Customer, at Customer’s sole expense, shall obtain and possess all permits and authorizations in accordance with all applicable laws and regulations for the construction, installation, design operation and maintenance of the Facility.

4. CUD shall furnish and install one or more standard watt-hour meters to read energy generated by Customer’s Facility. Customer shall provide and install a meter socket and connections in accordance with CUD’s metering standards. If the Customer desires more detailed metering equipment, all associated costs will be incurred by the Customer.

5. CUD shall have the right to have its representatives present at the final inspection made by the governmental authority having jurisdiction to inspect and approve the installation of the Generating Facility or battery storage. For interconnections involving battery storage, Customer shall be responsible for all inspection and commissioning fees.

Customer shall notify CUD in accordance with the terms of Section 12, herein, at least five (5) days prior to such inspection.

6. Customer shall not connect the Facility, or any portion of it, to CUD's distribution system, until written approval of Facility has been given to Customer by CUD. Such

CITY OF CORONA UTILITIES DEPARTMENT

ELECTRIC RATES &TARIFFS
115 Effective Date: November 20, 2024
approval shall not be unreasonably withheld.

7. Customer may reconnect its Facility to the CUD system following normal operational outages and interruptions without notifying CUD unless CUD has disconnected service, or CUD notifies Customer that a reasonable possibility exists that reconnection would pose a safety hazard.

8. If CUD has disconnected Service to the Facility, or CUD has notified Customer that a reasonable possibility exists that reconnection would pose a safety hazard, Customer may call CUD's Customer Service Center to request authorization to reconnect the Facility.

5. Design Requirements

1. Customer’s Facility, and all portions of it used to provide or distribute electrical power and parallel interconnection with CUD’s distribution equipment shall be designed, installed, constructed, operated, and maintained in compliance with this Rule.

Compliance with this section is mandatory.

2. Customer shall conform to all applicable solar or wind electrical generating system safety and performance standards established by CUD’s Electric Service Rule No. 21, the National Electrical Code (NEC), the Institute of Electrical and Electronics Engineers (IEEE), and accredited testing laboratories such as Underwriters Laboratories, and where applicable, rules of the Public Utilities Commission regarding safety and reliability, and applicable building codes.

6. Maintenance and Permits

1. Customer shall: (a) maintain the Facility and interconnection facilities in a safe and prudent manner and in conformance with all applicable laws and regulations including, but not limited to, requirements of Section 5 above, and (b) to the extent that future requirements may require, obtain any governmental authorizations or permits required for the operation of the Facility. Customer shall reimburse CUD for any and all losses, damages, claims, penalties, or liability CUD incurs as a result of Customer’s failure to obtain or maintain any governmental authorizations and permits required for construction and operation of the Customer’s Facility.

7. Access to Premises

1. CUD may enter Customer’s premises without prior notice (a) to inspect, at all reasonable hours, Customer’s protective devices and read or test any meter for the Facility and (b) to disconnect, at any time, without notice, the Facility if, in CUD’s sole opinion, a hazardous condition exists and that immediate action is necessary to protect persons, or CUD’s facilities, or property of others from damage or interference caused by (1) Customer’s Facility, or (2) Customer’s failure to comply with the requirements of this Rule.

8. Indemnity and Liability by Customer

1. Customer shall indemnify and hold CUD, its directors, officers, agents and employees

CITY OF CORONA UTILITIES DEPARTMENT

ELECTRIC RATES &TARIFFS
116 Effective Date: November 20, 2024
harmless against all loss, damages expense and liability to third persons for injury to or death of persons or injury to property caused by the Customer’s engineering design, construction, installation, ownership, maintenance or operations of the Facility in connection with this Agreement by reason of omission or negligence, whether active or passive. Customer shall, on CUD’s request, defend any suit asserting a claim covered by this indemnity. Customer shall pay all costs that may be incurred by CUD in enforcing this indemnity.

2. Neither CUD, its officers, agents or employees shall be liable for any claims, demands, costs, losses, causes of action, or any other construction, ownership, maintenance or operation of, or making of replacements, additions or betterment to, Customer’s Facility except to the extent actually caused by the sole and gross negligence of the CUD.

3. Neither CUD, its officers, agents or employees shall be liable for damages of any kind to the Facility caused by any electrical disturbance of the CUD system or on the system of another, whether or not the electrical disturbance results from the negligence of CUD.

9. Insurance

1. To the extent that Customer has currently in force all risk property insurance and comprehensive personal or commercial general liability insurance, Customer agrees that it will maintain such insurance in force for the duration of this Agreement. CUD and the City shall have the right to inspect or obtain a copy of the original policy or policies of insurance prior to commencing operation. In the event the solar generating system is greater than 30 kW (CEC AC), such insurance shall, by endorsement to the policy or policies, provide for thirty (30) calendar days written notice to CUD prior to cancellation, termination, alteration, or material change of such insurance.

CITY OF CORONA
2024 Electric Greenfield Utility
Rate Study
Final Report September 23, 2024

CITY OF CORONA
2024 ELECTRIC GREENFIELD UTILITY RATE STUDY

FINAL REPORT
Prepared for:

City of Corona
400 South Vicentia Avenue
Corona, CA 92882
Prepared by:

EES Consulting, a GDS Associates Company
16701 NE 80th St. Suite 102
Redmond, WA 98052
(425) 889-2700

September 23, 2024
Mr. Tom Moody
Director of Utilities
City of Corona
400 South Vicentia Avenue
Corona, CA 92882
Subject: 2024 Electric Greenfield Utility Rate Study
Dear Mr. Moody:

EES Consulting (EES), a GDS Associates Company,. is pleased to provide this 2024 Electric Greenfield Utility Rate Study to the City of Corona (City). This rate study includes a financial plan to determine the revenue requirements for the next five years and a comprehensive review of the City’s current rates based on the cost of service principles. This report outlines the approach, methodology, findings, and recommendations of the study. Each of the components of this study has enhanced the equitability of the rates we propose.

The proposed rates were developed utilizing the City’s customer usage data, billing records, accounting, operating and management records, capital plans, and reserve policies. Based on the City-provided data, key assumptions were made for the study using appropriate resources and our econometric and financial expertise.

It has been an absolute pleasure and honor to work with your City. We thank you, Ms. Hockett, Ms.

Kunkle, Ms. Betancourt, and Mr. Ma and all staff who helped complete this report.

Respectfully submitted,
Amber Gschwend
Managing Director EES Consulting
16701 NE 80th Street, Suite 102, Redmond, WA 98052
425.655.1042
[email protected]

City of Corona – 2024 Electric Greenfield Utility Rate Study i 1 CONTENTS
LIST OF TABLES................................................................................................................................. iii LIST OF FIGURES............................................................................................................................... iv 1 EXECUTIVE SUMMARY................................................................................................................ 1

1.1 Background ............................................................................................................................. 1

1.2 Purpose of Study ..................................................................................................................... 2

1.3 Rate Recommendations and Proposed Rates ......................................................................... 2

1.4 Current and Proposed Electric Rates....................................................................................... 2 2 METHODOLOGY ........................................................................................................................... 8

2.1 General Methodology .............................................................................................................. 8

2.2 Legal Considerations............................................................................................................... 8

2.3 Key Assumptions..................................................................................................................... 9 Escalation Factors .......................................................................................................................... 9 Customer and Sales Growth......................................................................................................... 10 Debt Service Coverage Ratios...................................................................................................... 11 3 FINANCIAL PLAN........................................................................................................................ 12

3.1 Revenues .............................................................................................................................. 12

3.2 Operating and Maintenance (O&M) Expense......................................................................... 13

3.3 Other Obligations................................................................................................................... 13 Capital Improvement Projects....................................................................................................... 13 Reserves ...................................................................................................................................... 14 Debt Service and Coverage Ratios............................................................................................... 15

3.4 Financial Plan Summary........................................................................................................ 16

3.5 Revenue Requirements ......................................................................................................... 18 4 COST OF SERVICE ANALYSIS .................................................................................................. 20

4.1 COSA Definition and General Principles................................................................................ 20

4.2 General Ratemaking Principles.............................................................................................. 21

4.3 Functionalization of Costs...................................................................................................... 22 Standard Functionalization ........................................................................................................... 22

4.4 Classification of Costs ........................................................................................................... 23 Standard Classification ................................................................................................................. 24 City of Corona Classification Method ............................................................................................ 25

4.5 Allocation of Costs................................................................................................................. 27 City of Corona Allocation Methodology ......................................................................................... 28 5 ELECTRIC RATE DESIGN .......................................................................................................... 32

5.1 Recommended Residential Rates.......................................................................................... 33

City of Corona – 2024 Electric Greenfield Utility Rate Study ii

5.2 Recommended Small Commercial (GS-1) Rates................................................................... 34

5.3 Recommended Medium Commercial (GS-2) Rates ............................................................... 35

5.4 Recommended Large Commercial (TOU-GS-3) Rates .......................................................... 36

5.5 Recommended Industrial (TOU-8) Rates............................................................................... 37

5.6 Recommended Pumping and Agriculture (TOU-PA-2) Rates................................................. 38

5.7 Recommended Lighting Rates............................................................................................... 40

5.8 Recommended Commercial Electric Vehicle Charging Rates................................................ 40 APPENDIX .......................................................................................................................................... 42

City of Corona – 2024 Electric Greenfield Utility Rate Study iii

LIST OF TABLES
Table 1. Rate Class Definitions ...............................................................................................................................3 Table 2. Proposed Revenue Adjustments FY 2024-25 to FY 2028-29 .................................................................3 Table 3. Current and Proposed Residential Rates (D)..........................................................................................4 Table 4. Current and Proposed Small General Service Rates (GS-1) .................................................................4 Table 5. Current and Proposed Medium General Service Rates (GS-2) .............................................................4 Table 6. Current and Proposed Large General Service Rates (TOU-GS-3) ........................................................5 Table 7. Current and Proposed Industrial Rates (TOU-8).....................................................................................5 Table 8. Current and Proposed Pumping and Agriculture Service Rates (TOU-PA).........................................6 Table 9. Current and Proposed Lighting Rates .....................................................................................................6 Table 10. Proposed Commercial Electric Vehicle Charging Rates .....................................................................7 Table 11. Expense Escalation Factors ................................................................................................................ 10 Table 12. Annual Meter Count FY 2023-24 to FY 2028-29.................................................................................. 11 Table 13. Annual Miscellaneous Revenue by Source, FY 2024 to FY 2029..................................................... 12 Table 14. Electric Utility Greenfield Operating Forecast, FY 2024 to FY 2029 ................................................ 13 Table 15. Operating Expenses by Expense Category, FY 2024 to FY 2029..................................................... 13 Table 16. Rate Study CIP Expenses and CIP Reserve, FY 2024 to FY 2029 .................................................... 14 Table 17. Electric Greenfield Reserve Target, FY 2024 to FY 2029 .................................................................. 14 Table 18. Electric Greenfield Utility Debt Service Coverage Ratio Calculation, FY 2024 to FY 2029 ........... 16 Table 19. Status Quo Financial Pro Forma for City of Corona Electric Greenfield, FY 2024 to FY 2029...... 17 Table 20. Proposed Financial Pro Forma for City of Corona Electric Greenfield System, FY 2024 to FY 2029................................................................................................................................................................. 18 Table 21. Revenue Requirements for City of Corona Electric Greenfield Utility, FY 2025............................. 19 Table 22. Functionalized Revenue Requirement FY 2025 ................................................................................. 23 Table 23. Functionalized Rate Base FY 2023...................................................................................................... 23 Table 24. Functionalized and Classified Revenue Requirement FY 2025........................................................ 27 Table 25. Functionalized and Classified Rate Base FY 2023 ............................................................................ 27

City of Corona – 2024 Electric Greenfield Utility Rate Study iv Table 26. Functionalized, Classified, and Allocated Rate Base FY 2023......................................................... 30 Table 27. Summary of FY 2025 Load Data .......................................................................................................... 30 Table 28. Allocated Revenue Requirement FY 2025 .......................................................................................... 31 Table 29. Total of Operating Functional Categories Allocated to Cost Components .................................... 31 Table 30. Recommended Rebalancing Proposal ............................................................................................... 32 Table 31. Residential: COSA Unit Costs, Current Rates, and Recommended FY 2025 Rates ...................... 34 Table 32. GS-1: COSA Unit Costs, Current Rates, and Recommended FY 2025 Rates ................................. 34 Table 33. GS-1: Bill Impact Example.................................................................................................................... 35 Table 34. GS-2: COSA Unit Costs, Current Rates, and Recommended FY 2025 Rates ................................. 35 Table 35. GS-2: Bill Impact Example.................................................................................................................... 36 Table 36. TOU-GS-3: COSA Unit Costs, Current Rates, and Recommended FY 2025 Rates ........................ 37 Table 37. TOU-GS-3: Bill Impact Example........................................................................................................... 37 Table 38. TOU-8: COSA Unit Costs, Current Rates, and Recommended FY 2025 Rates............................... 38 Table 39. TOU-8: Bill Impact Example ................................................................................................................. 38 Table 40. TOU-PA-2: COSA Unit Costs, Current Rates, and Recommended FY 2025 Rates......................... 39 Table 41. Lighting: Current Rates and Recommended FY 2025 Rates............................................................ 40 Table 42. EV Charging: Recommended FY 2025 Rates..................................................................................... 41

LIST OF FIGURES
Figure 1. City of Corona Electric Service Greenfield............................................................................................1 Figure 2. Electric Utility Greenfield Rate Study Process......................................................................................8 Figure 3. Electric Retail Sales (kWh) Forecast FY 2023-24 to FY 2033-34....................................................... 11 Figure 4. Electric Greenfield Cash Balances and Reserve Target with Current Rates, FY 2024 to FY 2029 15 Figure 5. Debt Service Coverage Ratio Under Current Rates, FY 2024 to FY 2029 ........................................ 16 Figure 6. EV Charging Rate Comparison with SCE ........................................................................................... 41

City of Corona – 2024 Electric Utility Greenfield Rate Study 1 1 EXECUTIVE SUMMARY

1.1 Background
The Electric Utility of the City of Corona (City) was established on April 4, 2001 by City Council Resolution No. 2001-25 in response to state-wide rolling blackouts and electric price instability. The City provides fully-bundled “Greenfield” electric service to residents and businesses within the City’s electric service area. New developments will become customers of the Corona Greenfield electric utility (Greenfield System) if they are in the City’s service area and capacity is available. The Greenfield System currently provides bundled delivery and power supply services to approximately 1,800 customers in 5 different areas of the City. The City also provides Direct Access energy procurement or “generation” services through the Direct Access Program to municipal and commercial customers within the City. The Direct Access Program is not a part of this rate study.

Figure 1 illustrates the City’s electric utility service area.

Figure 1. City of Corona Electric Service Greenfield

City of Corona – 2024 Electric Utility Greenfield Rate Study 2

1.2 Purpose of Study
The purpose of this analysis is to conduct a rate study which evaluates the City’s current rates and financial data and propose new rates, if necessary, that meet the City’s financial and strategic goals.

The primary objectives of this Study include:
• Projecting revenues and expenses for a ten-year study period • Proposing five-year revenue adjustments to fund the City’s projected financial needs • Proposing rates which do not overly impact customers
• Producing an administrative record which effectively summarizes all findings

1.3 Rate Recommendations and Proposed Rates

1.4 Current and Proposed Electric Rates
The Greenfield System services customers are based on class of service and one or more of the 12 rate schedules as provided in the City’s Electric Rates and Tariffs.1 The cost of service analysis (COSA) combines similar rate schedules for the cost allocation analysis but then develops rates for each of the current rate schedules. Table 1 describes the rate class and applicable rate schedules. 1 https://www.coronaca.gov/home/showpublisheddocument/2238/638550797549230000 Electric
 Adjusting rates annually by the recommended revenue adjustments of 4.0 percent per year.  Adjust rate levels differently across customer classes to recover each class’s unique cost of service. Effectively this realigns rates with cost of service.  Increasing the fixed proportion of rate collection.
 Including a rate category for commercial electric vehicle charging stations.  Separating the Public Benefits Charge from base rates.  Remove seasonal energy rates for non-TOU commercial classes.  Collect demand-related power supply costs throughout the year rather than just during summer peak periods.
 Increase demand rates for power supply and facilities charges based on cost of service.

City of Corona – 2024 Electric Utility Greenfield Rate Study 3 Table 1. Rate Class Definitions
Rate Class Schedule Notes
Residential D (Domestic Service) Applies to all single family and multifamily dwellings
Small General Service GS-1 Non-demand metered, < 20 kW/month Medium General Service GS-2 Demand-metered, above 20 kW and below 200 kW
Large General Service TOU-GS-3 Time of use and demand metered above 200 kW and below 500 kW
Industrial TOU-8 Time of use and demand metered above 500 kW Pumping and Agriculture PA-2, TOU-PA Demand metered service for pumping and agricultural usage (min of 70% total usage)
Lighting AL-2, TC-1, LS-3 Street lighting, outdoor lighting, and traffic control The City also provides net energy metering (NEM) and eligible renewable generation (ERG) service schedules. These services are considered in the rate study separately.

EES proposes the following rate and revenue adjustments to accomplish the City’s goals of capital and reserve funding as well as maintaining debt service coverage ratios. To maintain the proposed financial plan, the City should raise electric revenues by 4.0 percent each year of the study period. Table 2 shows the proposed revenue adjustments for the five-year rate study period.

Table 2. Proposed Revenue Adjustments FY 2024-25 to FY 2028-29 FY 2025 FY 2026 FY 2027 FY 2028 FY 2029
Recommended Adjustment 4.0% 4.0% 4.0% 4.0% 4.0%
The City will implement the fiscal year rates in January of each fiscal year. Tables 3 through 10 summarize the current and proposed electric rates based on the results of this study. Rates for FY 2025 through FY 2029 are shown in the Appendix.

City of Corona – 2024 Electric Utility Greenfield Rate Study 4 Table 3. Current and Proposed Residential Rates (D)
Current Rates Recommended
FY 2025
Fixed Charge, $/month Single Family: $0.88/day
Multi-Family: $0.67/day $15.90
Energy, $/kWh
Tier 1 Baseline $0.11808 $0.10100
Tier 2 101-130% Baseline $0.13741 $0.11100
Tier 3 131-200% Baseline $0.22696 $0.21000 Tier 4 over 200% Baseline $0.32337 Public Benefits Charge $/kWh Included in Energy Rate $0.00378 Table 4. Current and Proposed Small General Service Rates (GS-1) Current Rates Recommended
FY 2025
Fixed Charge, $/month Single Phase: $12.99
Three Phase: $3.16
Single Phase: $20.97
Three Phase: $3.16
Energy, $/kWh
Summer $0.17280 $0.15500
Winter $0.16872 $0.15500
Public Benefits Charge, $/kWh Included in Energy Rate $0.00378 Total Variable Rate $0.17024 $0.15878
Table 5. Current and Proposed Medium General Service Rates (GS-2) Current Rates Recommended FY
2025
Fixed Charge, $/month $71.50 $35.13
Demand, $/kW
Power Supply Summer Peak:(1) $20.67 Peak: (2) $8.27
Distribution Facilities: $7.35 Facilities: $15.74
Energy, $/kWh
Summer $0.09648 $0.05905
Winter $0.08738 $0.05905
Public Benefits Charge Included in Energy Rate $0.00378 Total Variable Rate $0.09087 $0.06283

1. Summer Peak is from 4 pm to 9 pm on weekdays during summer months

2. Peak is from 4 pm to 9 pm year-round

City of Corona – 2024 Electric Utility Greenfield Rate Study 5 Table 6. Current and Proposed Large General Service Rates (TOU-GS-3)

1. Summer Peak is from 4 pm to 9 pm on weekdays during summer months, except holidays

2. Mid-Peak is 4 pm to 9 pm on summer weekends except holidays

3. Peak is from 4 pm to 9 pm year-round
Table 7. Current and Proposed Industrial Rates (TOU-8)
Current Rates Recommended
FY 2025
Fixed Charge, $/month $346.00 $76.97
Demand, $/kW
Power Supply Summer Peak: (1) $16.91
Mid-Peak: (2) $5.71
Peak: (3) $8.31
Distribution Facilities: $8.31 Facilities: $15.06
Energy, $/kWh
Summer On-Peak $0.12675 $0.09630
Summer Mid-Peak $0.10299 $0.07319
Summer Off-Peak $0.07184 $0.05200
Winter Mid-Peak $0.10538 $0.07986
Winter Off-Peak $0.07509 $0.05200
Power Factor Adjustment, $/kVa $0.18 $0.18
Public Benefits Charge, $/kWh Included in Energy Rate $0.00378

1. Summer Peak is from 4 pm to 9 pm on weekdays during summer months, except holidays

2. Mid-Peak is 4 pm to 9 pm on summer weekends except holidays

3. Peak is from 4 pm to 9 pm pm year-round
Current Rates Recommended FY
2025
Fixed Charge, $/month $277.25 $49.30
Demand, $/kW
Power Supply Summer Peak:(1) $18.16
Mid-Peak:(2) $6.23
Peak:(3) $8.29
Distribution Facilities: $7.62 Facilities: $17.51
Energy, $/kWh
Summer On-Peak $0.13561 $0.09620
Summer Mid-Peak $0.11027 $0.07280
Summer Off-Peak $0.07706 $0.05200
Winter Mid-Peak $0.11282 $0.07986
Winter Off-Peak $0.08052 $0.05200
Power Factor Adjustment, $/kVa $0.18 $0.18
Public Benefits Charge, $/kWh Included in Energy Rate $0.00378

City of Corona – 2024 Electric Utility Greenfield Rate Study 6 Table 8. Current and Proposed Pumping and Agriculture Service Rates (TOU-PA) Current Rates January 2025
Proposed
July 2025
Proposed
January 2026
Proposed
Fixed Charge, $/month $63.25 $19.14 $19.14 $20.86
Demand, $/kW
Power Supply Summer
Peak:(1) $10.85
Peak: (2) $6.00 Peak: $12.00 Peak: $12.98
Distribution Facilities: $3.85 Facilities: $8.00 Facilities: $10.00 Facilities: $21.55 Energy, $/kWh
Summer On-Peak $0.13064 $0.10361 $0.10361 $0.09444
Summer Mid-Peak $0.10929 $0.07874 $0.07874 $0.07178
Summer Off-Peak $0.05226 $0.05595 $0.05595 $0.05100
Winter Mid-Peak $0.12255 $0.08592 $0.08592 $0.07832
Winter Off-Peak $0.05226 $0.05595 $0.05595 $0.05100
Power Factor Adjustment, $/kVa $0.18 $0.18 $0.18 $0.18720 Public Benefits Charge $/kWh Included in
Energy Rate
$0.00378 $0.00378 $0.00405

1. Summer Peak is from 4 pm to 9 pm on weekdays during summer months, except holidays

2. Peak is from 4 pm to 9 pm year-round
Table 9. Current and Proposed Lighting Rates
Current Rates Proposed FY 2025
Outdoor Area Lighting (AL-2)
Energy Charge, $/kWh $0.08224 $0.11678
Public Benefits Charge $/kWh Included in Energy Rate $0.00378 Customer Charge, $/month $7.00 $10.26
Street Lighting (LS-3)
Energy Charge, $/kWh $0.08224 $0.11678
Public Benefits Charge $/kWh Included in Energy Rate $0.00378 Customer Charge, $/month $7.00 $10.26
Traffic Control (TC-1)
Energy Charge, $/kWh $0.11407 $0.16345
Public Benefits Charge $/kWh Included in Energy Rate $0.00378 Customer Charge, $/month $9.49 $13.91
Three Phase, $/month $3.16 $4.64

City of Corona – 2024 Electric Utility Greenfield Rate Study 7 Table 10. Proposed Commercial Electric Vehicle Charging Rates Recommended FY 2025 Rates
Fixed Charge, $/month $76.97
Demand (Facilities), $/kW $15.06
Energy, $/kWh
On-Peak 4-9 pm $0.19710
Off-Peak All Other Hours $0.06570
Power Factor Adjustment, $/kVa $0.18
Public Benefits Charge $/kWh $0.00378

City of Corona – 2024 Electric Utility Greenfield Rate Study 8 2 METHODOLOGY

2.1 General Methodology
The Greenfield System cost of service analysis and rate design studies are based on industry best practices. Figure 2 presents the steps taken to develop the City’s proposed rates.

Figure 2. Electric Utility Greenfield Rate Study Process • Growth Projection: Project customer growth for the ten-year study period, FY 2023-2024 through FY 2033-34, using the City’s forecast growth data. Forecast revenues for the study period are based on the projected customer growth and current rate levels. • Financial Planning and Revenue Requirements: Develop a ten-year financial plan based on the projected revenues and annual costs which include both operating and capital expenses. The City’s target reserve level should also be considered as part of the financial planning. Based on the financial planning, revenue requirements are determined for each year of the study period. • Cost of Service: Evaluate the customer classifications and allocate costs based on their service requirements.
• Rate Design: Design rates to equitably recover the rate revenue requirements from each customer.

2.2 Legal Considerations
This section describes the legal framework considered in the development of the recommended rates to ensure that the calculated cost of service rates provide a fair and equitable allocation of costs to each customer class.

California Constitution‐Article XIII C (Proposition 26) California voters approved Proposition 26 on November 2, 2010. Proposition 26 amended Article XIII C of the State Constitution to expand the definition of “tax” to include “any levy, charge, or exaction of any Growth Projection
Financial Planning
and Revenue
Requirements
Cost of Service Rate Design

City of Corona – 2024 Electric Utility Greenfield Rate Study 9 kind imposed by a local government” with listed exceptions. By means of these exceptions, Article XIII C classifies several types of charges, in addition to property-related charges, that are not taxes, such as charges for specific services or benefits, regulatory charges and penalties.

Article XIII C’s definition of “tax” lists the following exceptions: (1) a charge imposed for a specific benefit conferred or privilege granted directly to the payer that is not provided to those not charged, and which does not exceed the reasonable costs to the local government of conferring the benefit or granting the privilege; (2) a charge imposed for a specific government service or product provided directly to the payer that is not provided to those not charged, and which does not exceed the reasonable costs to the local government of providing the service or product; (3) a charge imposed for the reasonable regulatory costs to a local government for issuing licenses and permits, performing investigations, inspections, and audits, enforcing agricultural marketing orders, and the administrative enforcement and adjudication thereof; (4) a charge imposed for entrance to or use of local government property, or the purchase, rental, or lease of local government property; (5) a fine, penalty, or other monetary charge imposed by the judicial branch of government or a local government, as a result of a violation of law; (6) a charge imposed as a condition of property development; and (7) assessments and property-related fees imposed in accordance with the provisions of Article XIII D.

Proposition 26 also provides that the local government bears the burden of proving by a preponderance of the evidence that a levy, charge, or other exaction is not a tax, that the amount is no more than necessary to cover the reasonable costs of the governmental activity, and that the manner in which those costs are allocated to a payer bear a fair or reasonable relationship to the payer’s burdens on, or benefits received from, the governmental activity. Like the proportionality requirements of Article XIII D, assessment of rates under these requirements, if applicable, would be supported by the cost of service approach.

2.3 Key Assumptions
A base year FY 2024-25 was selected for which budgetary costs are to be analyzed and rates to be established for this study. The financial plan was built for the next ten years, including the five-year study period FY 2025-26 through FY 2029-30 with a detailed revenue adjustment plan. The City’s fiscal year starts on July 1 and ends on June 30.

Escalation Factors
The financial plan was built based on an assumption in the projected escalation of revenues and expenses associated with both operations and maintenance (O&M) and capital improvement projects (CIPs). Bureau of Labor Statistics (BLS) Los Angeles-Long Beach-Anaheim Consumer Price Index (CPI), Federal Reserve Bank of St. Louis (FRED) Economic Research Division, Quarterly Census of

City of Corona – 2024 Electric Utility Greenfield Rate Study 10 Employment and Wages (QCEW), and Engineering News Record (ENR) Building Cost Index (BCI).

Escalation factors used in this study are shown in Table 11. The Services and supplies escalator is based on the 3-year average of BLS CPI for all items through April 2024. This time period was selected to reflect the ongoing inflation observed in the electric utility industry. Cost drivers for electric utility operation and maintenance costs are largely based on the cost of distribution facilities. The Handy-Whitman Index (HWI)2
is a cost index frequently used in the electric utility industry. The HWI for electric distribution plant has increased by an average of 25% between the two most recent years published (2022-2023). While inflationary pressures have eased broadly in the economy, electric utilities are still facing high costs and long-lead times for materials and stores.

The Payroll escalation factor was provided by City staff based on historical actual costs and unknown impacts of current employee bargaining unit negotiations. The Power Supply cost escalator was taken from power supply cost forecasts provided by the City’s consultant.

Table 11. Expense Escalation Factors
Category FY 2025 FY 2026 FY 2027 FY 2028 FY 2029
Payroll 0.0% 8.0% 8.0% 4.0% 4.0%
Other Employee 0.0% 3.2% 3.2% 3.2% 3.2%
Services Supplies 0.0% 4.7% 4.7% 4.7% 4.7%
Power Supply 0.0% 5.0% 3.4% 3.4% 3.4%
CIP 0.0% 4.0% 4.0% 4.0% 4.0%
Customer and Sales Growth
Customer growth was forecast conservatively based on new service requests. It was assumed that per account electric use would remain stable over the study period with the exception of new large customers anticipated to begin taking service in 2024 and 2025. These large customers are a mix of electric vehicle (EV) charging stations, mixed commercial, multifamily dwellings, and a hotel. The City expects to add approximately 4.9 MW of load in the next 12-24 months as a result of these new customers.

There are currently approximately 1,936 electric meters connected to the Greenfield System. Figure 3 shows the annual electric customer growth for the study period. Table 12 shows the projected number of meters for all customer classes during the rate setting period. 2 Whitman, Requardt, and Associates. The Handy-Whitman Index of Public Utility Construction Costs: Trends of Construction Costs. E-6 Pacific Region.

City of Corona – 2024 Electric Utility Greenfield Rate Study 11 Figure 3. Electric Retail Sales (kWh) Forecast FY 2023-24 to FY 2033-34 Table 12. Annual Meter Count FY 2023-24 to FY 2028-29
Rate Schedule FY 2024 FY 2025 FY 2026 FY 2027 FY 2028 FY 2029 Residential (D) 1,323 1,323 1,373 1,373 1,373 1,373
GS-1 372 373 373 373 373 373
GS-2 160 160 160 160 160 160
TOU-GS-3 8 11 11 11 11 11
TOU-8 10 13 13 13 13 13
Pumping and Agriculture 2 2 2 2 2 2
Lighting 61 61 61 61 61 61
Total 1,936 1,943 1,993 1,993 1,993 1,993
The above forecasts are used in both the financial plan and the cost of service analysis.

Debt Service Coverage Ratios
The City’s debt covenants require a certain ratio of net revenue in excess of operating expenses. Debt service coverage ratios are one of the main financial plan drivers of the revenue adjustments. When calculating debt service coverage requirements, the City must maintain a net revenue of 125 percent, or a 1.25 debt service coverage ratio (DSCR) to avoid facing technical default.

City of Corona – 2024 Electric Utility Greenfield Rate Study 12 3 FINANCIAL PLAN
EES prepared a 10-year financial model for the Greenfield System to meet the City’s long-term financial goals. This section of the report details the financial forecast.

3.1 Revenues
Based on the account growth and demand projections as described in Section 3, EES forecasted retail rate revenues generated from customer rates using the current electric rates. Retail rate revenue is approximately $10.6 to $11.0 million annually. Other operating income and non-operating revenue are estimated to provide supplemental revenue each year as shown in Table 13. Surplus sales include the resale of excess power supply. AB32 revenues are the revenues earned by the utility for its allocation of carbon allowances through California’s Cap-and-Trade program. Finally, daily damages include the estimated payments the utility receives for the delayed commercial operation date for a contracted wind resource.

Table 13. Annual Miscellaneous Revenue by Source, FY 2024 to FY 2029 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028 FY 2029
Interest on Investments $601,018 $762,323 $800,439 $800,439 $800,439 $800,439 Other Interest Income $31,028 $36,627 $29,763 $24,186 $18,427 $12,481 Services to Other Funds $4,620 $4,600 $4,600 $4,600 $4,600 $4,600 Misc. Fees $132,774 $66,500 $66,500 $66,500 $66,500 $66,500 AB 32 Revenues $580,000 $870,000 $870,000 $870,000 $870,000 $870,000 Surplus Sales $774,300 $1,551,286 $2,144,126 $2,144,126 $2,144,126 $2,144,126 Daily Damages (Solar) $101,376 $462,551 $0 $0 $0 $0
Rental/Lease Income $109,000 $113,000 $118,000 $118,000 $118,000 $118,000 Total $2,334,116 $3,866,887 $4,033,428 $4,027,851 $4,022,092 $4,016,146 The system’s total revenue for the study period is estimated to be approximately $12.9 to $15.0 million annually under current rates. Table 14 shows the projected revenue flow for the study period (FY 2023- 24 – FY 2028-29) without any revenue adjustments. Projections are based on electric use and customer growth projections, as well as other operating and non-operating revenue estimates provided by City staff.

City of Corona – 2024 Electric Utility Greenfield Rate Study 13 Table 14. Electric Utility Greenfield Operating Forecast, FY 2024 to FY 2029 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028 FY 2029
Revenue from Rates $10,590,000 $10,479,000 $10,956,112 $10,956,112 $10,956,112 $10,956,112 Other Operating Revenue $1,579,870 $2,954,937 $3,085,226 $3,085,226 $3,085,226 $3,085,226 Non-Operation Revenues $754,246 $911,950 $948,202 $942,625 $936,867 $930,920 Total $12,924,116 $14,345,887 $14,989,540 $14,983,963 $14,978,204 $14,972,257

3.2 Operating and Maintenance (O&M) Expense
The majority of O&M expenses for the Greenfield System are in purchased power supply costs as shown in Table 15. These costs are increasing over time due to forecast market conditions and current contract arrangements. The systems power supply costs include all costs associated with serving retail customers including energy purchases, renewable energy, transmission and ancillary services, and capacity.

Distribution O&M are the annual ongoing costs of maintaining the electric distribution system and does not include new capital investments. Customer service and account costs are the cost of maintaining the utility billing system, meter reading, customer programs, new service requests, and staffing to take customer calls. The administrative and general expense includes the overhead needed to run the electric utility such as property insurance and staffing.

Table 15. Operating Expenses by Expense Category, FY 2024 to FY 20293 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028 FY 2029
Purchased Power Cost $8,239,397 $10,801,225 $10,872,100 $11,172,908 $11,484,571 $11,807,506 Distribution O&M $549,215 $505,074 $536,698 $570,438 $595,298 $621,248 Customer Accts & Svc $505,902 $672,638 $469,204 $479,668 $488,404 $497,533 Administration & General $1,658,408 $1,738,294 $1,815,816 $1,896,850 $1,981,506 $2,069,995 Total $10,952,922 $13,717,231 $13,693,818 $14,119,865 $14,549,778 $14,996,283

3.3 Other Obligations
Other obligations included in the financial plan are capital improvement, franchise fee, debt service obligations, and reserve contributions made from rates. These are described below.

Capital Improvement Projects
The City plans to spend an average of $500,000 a year on electric related capital expenditures during the rate setting period. While the projects planned only total an average of $500,000 per year, the electric utility department anticipates major replacements will be needed during the 10-year planning period. 3 District staff provided current year operating expenses by category, projections are based on individual line-item inflationary factors shown in Table 13.

City of Corona – 2024 Electric Utility Greenfield Rate Study 14 These replacements include investments to improve reliability and resiliency of the electrical grid4.

Therefore, in addition to the planned projects, the City’s financial plan provides revenue to build a capital savings balance. In total, the City plans for $1.6 million per year to be either used directly for capital projects or to be saved for future replacements, as shown in Table 16. The 10-year savings target of $13.1 million for future capital projects is incorporated into the financial plan.

Table 16. Rate Study CIP Expenses and CIP Reserve, FY 2024 to FY 20295 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028 FY 2029
Total CIP Expense $2,094,029 $1,600,000 $1,600,000 $1,600,000 $1,600,000 $1,600,000 CIP Projects Planned $2,094,029 $810,000 $693,323 $231,000 $253,000 $545,000 More detail on reserve balances are provided below.

Reserves
The City must maintain an appropriate reserve balance to ensure the day-to-day operation will continue during emergencies and guarantee the future stability of the system. The City’s financial goal is to build an appropriate level of cash reserves for the reserve fund included in the financial plan of this Study.

Reserve target for the Greenfield System is described below:
 Operating Reserve: Three months of operating expenses plus annual depreciation.

The reserve target at the end of the 10-year study period reaches $4.9 million. Table 17 shows the City’s reserve targets for FY 2023-24 through FY 2028-29 based on the current reserve policy. Figure 4 displays the resulting cash balances versus the reserve target under the current rates. Figure 4 demonstrates that the operating reserve is fully funded beginning FY2025.

Table 17. Electric Greenfield Reserve Target, FY 2024 to FY 2029 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028 FY 2029
Operating Reserve $3,213,509 $3,904,527 $3,906,793 $4,015,745 $4,125,747 $4,236,870 In addition to the operating reserve, the Greenfield electric utility tracks three other reserve accounts:

1. Unrestricted – Includes all unrestricted cash including contributions held for future CIP as discussed above.
4 Replacements include gas switches, breakers, and PME replacements as well as a portion of underground cable.
5 District’s 10-year CIP budget was used for project cost, project type, and funding source

City of Corona – 2024 Electric Utility Greenfield Rate Study 15

2. Public Benefits Charge (PBC) Reserve – Contributions are made from the PBC revenues which is equal to 2.85% of retail revenues. Fund use is restricted to low-income or energy efficiency program expenditures.

3. Greenhouse Gas Reserve – Contributions are made from AB 32 auction proceeds. Fund use is restricted to renewable energy expenses.

At current rate levels and projected fund use, the aggregate reserve level decreases over the planning period. Total unrestricted cash decrease from $5.7 million to $5.5 million, of which, $5.5 million is needed to fund future CIP.

Figure 4. Electric Greenfield Cash Balances and Reserve Target with Current Rates, FY 2024 to FY 2029
Debt Service and Coverage Ratios
The City’s Greenfield system does not carry any traditional debt, however, there is a pension obligation bonds (POB) payment. This obligation is approximately $250,000 a year during the study period. Table 18 shows the DSCR under the current finances detailed in the previous tables. To derive the DSCR, net revenue is divided by the total debt service in each year.

City of Corona – 2024 Electric Utility Greenfield Rate Study 16 Table 18. Electric Greenfield Utility Debt Service Coverage Ratio Calculation, FY 2024 to FY 2029
FY 2024 FY 2025 FY 2026 FY 2027 FY 2028 FY 2029
Total Revenue $12,910,916 $14,345,887 $14,989,540 $14,983,963 $14,978,204 $14,972,257 Total Operating Expense $10,952,922 $13,717,231 $13,693,818 $14,119,865 $14,549,778 $14,996,283 Total Debt Service $229,138 $238,897 $248,271 $254,605 $260,951 $254,857 DSCR 8.55 2.63 5.22 3.39 1.64 -0.09
Under the current rates, the City will be in technical default beginning in FY 2029 as net revenues are not 125 percent greater than debt service payments. Figure 5 shows the projected debt service coverage ratios based on the current financial plan.

Figure 5. Debt Service Coverage Ratio Under Current Rates, FY 2024 to FY 2029

3.4 Financial Plan Summary
Based on the projected total revenue and necessary costs to be recovered during the study period, EES prepared a financial plan that will generate sufficient revenues for the day-to-day operation and annual CIP and make appropriate contributions to reserves. The City’s Greenfield fund currently has a projected ending cash balance of $5.7 million in FY 2024. Table 19 shows the status quo pro forma with no revenue adjustments and the resulting ending balances based on the revenues and expenses outlined in this section.

City of Corona – 2024 Electric Utility Greenfield Rate Study 17 Table 19. Status Quo Financial Pro Forma for City of Corona Electric Greenfield, FY 2024 to FY 2029
Restricted funds balance includes the PBC Reserve, Greenhouse Gas Reserve, and Operating Reserve.

The unrestricted balance includes funds saved for future CIP and cash for working capital.

The transfers under Revenues of approximately $164,000 in FY 2025 is an interfund loan. This revenue is split between the Greenfield and Direct Access electric customers based on relative share of total energy.

Table 20 shows the proposed pro forma for the study period with the recommended revenue adjustments per year. All revenue adjustments will occur in January of the Fiscal Year.

FY 2024 FY 2025 FY 2026 FY 2027 FY 2028 FY 2029
Rate Increase 0% 0% 0% 0% 0%
Month Implemented January January January January January Cash Position Opening Balance $13,071,906 $12,698,043 $12,228,235 $12,478,797 $12,748,593 $12,549,004 Revenues
Retail Rate Revenue $10,590,000 $10,479,000 $10,956,112 $10,956,112 $10,956,112 $10,956,112 Other Revenues $2,334,116 $3,866,887 $4,033,428 $4,027,851 $4,022,092 $4,016,146 Transfers $163,490 $164,205 $133,437 $137,787 $142,279 $146,917 Total Revenues $13,087,606 $14,510,092 $15,122,976 $15,121,749 $15,120,482 $15,119,174 Operating Expenses $11,187,897 $13,979,529 $13,977,194 $14,409,973 $14,846,195 $15,298,838 Net Operating Revenues $1,899,709 $530,564 $1,145,783 $711,776 $274,288 -$179,664 Current Rate Funded Debt Service $179,543 $190,371 $201,898 $210,980 $220,877 $218,898 New Debt Service $0 $0 $0 $0 $0 $0
Total $179,543 $190,371 $201,898 $210,980 $220,877 $218,898 Total Operating and Debt Service $11,367,439 $14,169,900 $14,179,092 $14,620,953 $15,067,072 $15,517,736 Total Operating and Debt Net Revenues $1,720,166 $340,192 $943,885 $500,796 $53,411 -$398,562 Capital Expenditure $2,094,029 $810,000 $693,323 $231,000 $253,000 $545,000 Net Income -$373,863 -$469,808 $250,562 $269,796 -$199,589 -$943,562 Cash Ending Balance $12,698,043 $12,228,235 $12,478,797 $12,748,593 $12,549,004 $11,605,442 Restricted Funds Balance $7,005,185 $9,048,639 $7,905,534 $6,775,938 $6,441,711 $6,394,984 Unrestricted Ending Balance $5,692,858 $3,179,596 $4,573,263 $5,972,655 $6,107,293 $5,210,458

City of Corona – 2024 Electric Utility Greenfield Rate Study 18 Table 20. Proposed Financial Pro Forma for City of Corona Electric Greenfield System, FY 2024 to FY 2029

3.5 Revenue Requirements
Table 21 displays the Greenfield Systems revenue requirements for FY 2024-25. The total expense is offset by other operating revenues and non-operating revenues to compute a pure portion of revenue requirements that need to be recovered from customers’ rates. EES proposes annual revenue adjustments of 4.0 percent FY 2024-25 through FY 2028-29 to reach the financial goals set by the City.

FY 2024 FY 2025 FY 2026 FY 2027 FY 2028 FY 2029
Rate Increase 4% 4% 4% 4% 4%
Month Implemented January January January January January Cash Position Opening Balance $13,071,906 $12,698,043 $12,437,815 $13,582,396 $15,220,216 $16,881,616 Revenues
Retail Rate Revenue $10,590,000 $10,688,580 $11,850,130 $12,324,136 $12,817,101 $13,329,785 Other Revenues $2,334,116 $3,866,887 $4,033,428 $4,027,851 $4,022,092 $4,016,146 Transfers $163,490 $164,205 $133,437 $137,787 $142,279 $146,917 Total Revenues $13,087,606 $14,719,672 $16,016,995 $16,489,773 $16,981,472 $17,492,848 Operating Expenses $11,187,897 $13,979,529 $13,977,194 $14,409,973 $14,846,195 $15,298,838 Net Operating Revenues $1,899,709 $740,144 $2,039,802 $2,079,800 $2,135,277 $2,194,009 Current Rate Funded Debt Service $179,543 $190,371 $201,898 $210,980 $220,877 $218,898 New Debt Service $0 $0 $0 $0 $0 $0
Total $179,543 $190,371 $201,898 $210,980 $220,877 $218,898 Total Operating and Debt Service $11,367,439 $14,169,900 $14,179,092 $14,620,953 $15,067,072 $15,517,736 Total Operating and Debt Net Reven $1,720,166 $549,772 $1,837,903 $1,868,820 $1,914,400 $1,975,112 Capital Expenditure $2,094,029 $810,000 $693,323 $231,000 $253,000 $545,000 Net Income -$373,863 -$260,228 $1,144,580 $1,637,820 $1,661,400 $1,430,112 Cash Ending Balance $12,698,043 $12,437,815 $13,582,396 $15,220,216 $16,881,616 $18,311,727 Restricted Funds Balance $7,005,185 $9,048,639 $7,905,534 $6,775,938 $6,441,711 $6,394,984 Unrestricted Ending Balance $5,692,858 $3,389,176 $5,676,862 $8,444,278 $10,439,905 $11,916,743

City of Corona – 2024 Electric Utility Greenfield Rate Study 19 Table 21. Revenue Requirements for City of Corona Electric Greenfield Utility, FY 2025 Revenue Requirement FY 2025
O&M Expenses $13,717,231
Franchise Fees $213,772
Debt Service $238,897
Capital Expenditures $810,000
Other Operating Revenue ($2,954,937)
Non-Operating Revenue ($911,950)
Net Balance from Operations ($424,433)
Rate Revenue Requirement $10,688,580

City of Corona – 2024 Electric Utility Greenfield Rate Study 20 4 COST OF SERVICE ANALYSIS
The objective of the COSA is to analyze costs and equitably assign those costs to customers commensurate with the cost of serving those customers. The founding principal of cost allocation is the concept of cost-causation. Cost-causation evaluates which customer or group of customers causes the utility to incur certain costs by linking system facility investments and operating costs to serve certain facilities to the services used by different customers. This section of the report will discuss the general approach used to apportion the utility’s cost of service and provide a summary of the results.

4.1 COSA Definition and General Principles
A COSA study allocates the costs of providing utility service to the various customer classes served by the utility based upon the cost-causal relationship associated with specific expense items. This approach is taken to develop a fair and equitable designation of costs to each customer class, where customers pay for the costs that they incur. Because the majority of costs are not incurred by any one type of customer, the COSA becomes an exercise in spreading joint and common costs among the various classes using factors appropriate to each type of expense. The COSA is the second step in a traditional three-step process for developing service rates. The first step is the development of the test period revenue requirement for the utility, which is the starting input for the COSA. The COSA then spreads the revenue requirement across the various customer classes, creating per unit costs by class. In the third step, rates are designed for each customer class, with per unit costs being one consideration in setting the appropriate rate levels.

A COSA study can be performed using embedded costs or marginal costs. Embedded costs generally reflect the actual costs incurred by the utility and closely track the costs kept in its accounting records.

Marginal costs reflect the cost associated with adding a new customer and are based on costs of facilities and services, if incurred at the present time. While marginal costs can be valuable for designing rates in certain instances, marginal costs are generally higher than embedded costs. Therefore, the use of a marginal COSA study usually requires that all costs be scaled back to a level equal to the embedded cost revenue requirement established using actual or projected costs from an “accounting” perspective.

This study uses an embedded COSA as its standard methodology. Therefore, the City’s electric utility embedded cost revenue requirement and existing rate base investment are used in developing the COSA results. Both the utility’s revenue requirement (ongoing expenses) and the value of its fixed assets (plant) are spread across customer classes. The allocation of the fixed assets is then used to spread ongoing O&M costs according to how each class utilizes the utility investments.

City of Corona – 2024 Electric Utility Greenfield Rate Study 21 There are three basic steps to follow in developing a COSA, or spreading expenses and fixed asset values across customers, namely:
 Functionalization
 Classification
 Allocation
Functionalization separates costs into major categories that reflect the utility’s plant investment and different services provided to customers. Plant investment includes infrastructure such as control panels, switches, transformers, and wires and it includes other necessary investments to run the utility business such as software or property. The primary functional categories are production, transmission, distribution and general.

Classification determines the portion of the cost that is related to specific cost-causal factors, such as those that are demand-related, energy-related or customer-related. Production costs are related to supplying and transporting power to customers on the system. Transmission costs are related to the bulk transfer of power throughout the system, which is designed to meet the peak demand requirement. The distribution system is designed to extend service to all customers attached to the system and to meet the peak load capacity requirement of each customer. Additionally, costs can be classified based on system revenues or directly assigned to a customer or group of customers.

Allocation of costs to specific customer classes is based on the customer’s contribution to the specific classifier selected. For instance, demand-related costs are allocated to a customer group using that customer group’s contribution to the particular measurement of system demand, whether coincident peak, non-coincident peak or some variation determined to be appropriate for the particular cost item. An analysis of customer requirement, loads and usage characteristics is completed to develop allocation factors reflecting each of the classifiers employed within the COSA. The analysis may include an evaluation of the system design and operations, its accounting and physical asset records, customer load data and special studies.

4.2 General Ratemaking Principles
While this section does not address the design of rates, it is important to note that the COSA results will be one of the considerations when the process of designing rates for various customer classes begins.

The basic goals of rate design include:
 The utility has an ability to collect the appropriate revenue requirement  Utility revenues and customer rates are stable and predictable  Proper price signals are sent to create efficiency of resources

City of Corona – 2024 Electric Utility Greenfield Rate Study 22  Rates are fair and equitable among customers and avoid undue discrimination  Rates are simple, easy to understand and feasible for the utility to implement The COSA is generally used to assist in meeting the second and fourth goals of rate design. Price signals are best if they reflect the specific costs incurred. Rates are generally considered fair and equitable if customers are deemed to pay their share of the costs incurred by the utility. Additionally, the first goal is met as long as the COSA is based on the appropriate revenue requirement, and the use of a consistent COSA methodology contributes towards the second goal. Rates are more stable through time if the COSA methodology is not significantly changed every time a rate application is made.

4.3 Functionalization of Costs
The first step in the COSA process following finalization of the revenue requirement is to functionalize the revenue requirement and the rate base (plant). Functionalization is the separation of cost data into the functional activities performed in the operation of a utility system (i.e., power supply, transmission, distribution and customer service). Functionalization was accomplished using the City’s system of accounts, which largely segregates costs in this manner.

In addition to the functionalized costs, certain joint costs are spread to each functional category based on the relationship of the joint cost to the business function. These joint costs include such items as administrative and general costs.

Standard Functionalization
Plant investment costs or rate base are generally functionalized into production, transmission, distribution and general cost categories. The functionalization of rate base typically is very straightforward as costs for the different functions are readily identifiable and rate base accounts are maintained by functional categories.

Expense accounts are also typically kept according to these basic functional categories, with expense items associated with certain types of plant being treated in the same manner as the corresponding plant account.

The two areas where there generally are differences in functionalization among utilities are in the treatment of general plant and administrative and general (A&G) expenses. Typically, general plant is considered a separate functional category. Some utilities, when their internal accounting systems can support such an assignment process, will record general plant investment by loading the costs into the other functional categories, much like an overhead assignment or a form of activity-based accounting.

City of Corona – 2024 Electric Utility Greenfield Rate Study 23 On the expense side, A&G costs can be treated in much the same way. Generally, they are treated as a separate expense category that can be spread to functions based upon all other O&M expenses.

However, they can also be spread to functions on the basis of total net plant, labor ratios or, in some cases, directly assigned as part of the activity-based accounting approach.

Table 22 displays the functionalization of the FY 2025 revenue requirement. Because the City does not own any transmission assets, only product (power supply) and distribution are shown.

Table 22. Functionalized Revenue Requirement FY 2025
Revenue Requirement Category Total Production Distribution Purchased Power $10,801,225 $10,801,225 $0
Distribution O&M $505,074 $0 $505,074
Customer Service, Accounts & Sales $672,638 $185,000 $487,638 Admin & General $1,738,294 $268,990 $1,469,304
Taxes (Franchise Fee) $213,772 $0 $213,772
Interest & Debt Service $238,897 $0 $238,897
Other Contributions ($424,433) ($1,743,483) $1,319,051
Capital Projects Funded from Rates $810,000 $0 $810,000 Other Revenues ($3,866,887) ($3,020,508) ($846,379)
Total $10,688,580 $6,491,223 $4,197,357
Table 23 summarizes the functionalization of the City’s fixed assets related to the electric utility. All fixed assets are functionalized as distribution.

Table 23. Functionalized Rate Base FY 2023
Description FERC Cost Account(s) Amount (millions) Functionalized To:

Distribution 360-373 $15.0 100% Distribution
General Plant 389-399 $0.2 100% Distribution
Total Gross Plant $15.2

4.4 Classification of Costs
The second step in performing a cost of service analysis is to classify the functionalized expenses to traditional cost causation categories. These cost causation categories can be directly related to specific consumption behavior or system configuration measurements such as coincident peak (CP) or noncoincident peak (NCP) demand, energy or number of customers. Each classification category will have a specific allocator that, when applied, will distribute those costs among the appropriate customer classes during the allocation phase of the analysis.

City of Corona – 2024 Electric Utility Greenfield Rate Study 24 Functionalized power purchases, generation and transmission system costs are classified as demandrelated and/or energy-related and in some instances directly assigned, while distribution costs are classified as demand- or customer-related, or directly assigned to specific customer classes of service.

Standard Classification
The three most general classification categories are demand-related, energy/commodity-related and customer-related. Within these three categories there are multiple ways of defining each option as well as varying ways to split costs between two or more classifiers. For example, demand- and energy-related costs can be separated by seasonal distinctions as well as to reflect peak/off peak consumption periods.

Customer-related costs could be separated by demand and customer categories, while customer categories can distinguish between actual customer and weighted customer characteristics. Other classifiers sometimes used in the process include revenue-related and direct assignment. In addition, there are many instances where costs are not specifically classified to a particular category but rather in the same manner as an individual cost account or subtotal of specific cost accounts. For example, some of the overhead costs, like Administrative & General, are classified based on how all other O&M costs are classified which includes a classification to energy, demand, or customer.

Generally, power production and purchased power costs are classified by a combination of demand and energy. Transmission costs are generally classified as peak demand, while distribution costs are generally split between demand and customer. The City’s electric utility purchases transmission service from the California Independent System Operator (CAISO). CAISO provides the load balancing services for much of the State. Because CAISO bills transmission based on energy, transmission costs for the City are classified as energy.

There are two methodologies that can be used to classify distribution costs: 100% demand and minimum system. The 100% demand methodology assumes that the distribution system is built to meet the noncoincident peak. Therefore, distribution costs are classified as 100% demand-related. Specific distribution costs are sometimes split between demand and customer according to a minimum system approach.

This approach reflects the philosophy that the system is in place in part because there are customers to serve throughout the service territory expanse, and that a minimally sized distribution system is needed to serve these customers even if they only use 1 kWh of energy per year. The concept follows that any costs associated with a system larger than this minimal size are due to the fact that customers “demand” a delivery quantity greater than the minimum unit of electricity and that therefore, those costs should be treated as demand-related. Because the residential class tends to have a higher share of the number of customers as compared to the share of non-coincident peak, the minimum system methodology tends to

City of Corona – 2024 Electric Utility Greenfield Rate Study 25 allocate more costs to the residential customer class and customer charges tend to be higher than with the 100% demand methodology.

The process of cost classification is the area within the COSA that can create considerable cost variability between customer classes due to differences in system configurations, demand measurements and assignment philosophy. The complexity of the entire COSA process is further compounded since, in some cases, the classification category is clear, but the specific allocator is not. For example, a particular cost item may clearly be peak demand-related but that demand can be measured as either a single coincident peak for the year, a 2 coincident peak (CP) approach to reflect seasonal considerations, the sum of 12 monthly coincident peaks or through some other approach such as “Average & Excess.” City of Corona Classification Method
The following describes the specific classifiers used in the City’s electric COSA within each of the four functions.

Power Supply
Classifying power supply costs to demand and energy (commodity) components requires the evaluation of a number of complex, interrelated factors. Consideration must be given to what or who caused the power supply purchase to be made, and to the uses to which it will be put (i.e., meeting demand and energy requirement). Within this study, power supply costs are classified to demand and energy based on the City’s power cost forecast for the test period. The specific classifiers used for the power supply function include Energy and Demand.

Energy-related costs are those that vary with the total amount of electricity consumed by a customer.

Electricity usage measured in kWh is used in this portion of the analysis as well. Energy costs are the costs of consumption over a specified period of time, such as a month or year.

Demand-related costs are those that vary with the maximum demand or the maximum rates of power supply to customer classes. Customer and system demand for this analysis were measured in kW.

Demand costs are generally related to the size of facilities needed to meet a customer’s maximum demand at any point in time.

All of the City’s power supply costs are purchases related to energy including most transmission purchases. Transmission purchases through CAISO or Southern California Edison (SCE) are included in this section of the revenue requirement. CAISO wheeling and the various facility charges are classified as demand-related since those costs are incurred by the utility based on demand readings.

City of Corona – 2024 Electric Utility Greenfield Rate Study 26 Transmission (Utility-Owned)
The transmission function includes the utility’s own transmission assets associated with providing power to the City’s distribution system. Transmission services that the City purchases in order to facilitate the delivery of wholesale power purchases to the City’s service area are included in power supply costs. The costs associated with the local utility’s transmission service include only those costs for operating and maintaining the transmission lines, poles, towers, substations, etc. used to deliver power to the distribution network. The cost of providing transmission service to a customer is considered to be directly proportional to the demand that customer imposes on the system. The City does not own transmission equipment; therefore, these line items are not included in the analysis.

Distribution
Distribution services include all services required to get energy supply from the point of interconnection between the transmission system and the utility’s service area to the end user of the power. Classifying distribution costs requires a special analysis of the nature of the costs. Because the City has collected billed demand data, the distribution system costs are classified as demand-related using the 100% demand approach described earlier.

Customer
Customer-related services include all services related to the presence of customers on the system, not to customer usage. These services include meter reading, billing, collections, advertising, etc. Customerrelated costs vary with the number and type of customers. They do not vary with system supply levels.

These costs are sometimes referred to as “readiness to serve” or “availability” charges. Customer costs are incurred by the utility to have electricity supply readily available for a customer whether it is utilized or not.

There are two types of customer-related cost classification categories—actual and weighted. Actual customer costs vary proportionally with the addition or deletion of a customer, regardless of the size or usage characteristics of the customer. An example of an actual customer-related cost is billing services needed to develop monthly customer bills. In contrast, a weighted customer cost reflects a disproportionate cost attributable to the addition or deletion of a customer. An example of weighted customer costs is meter-reading expenses. In some cases, it takes less time and effort to read a residential energy meter than it does to serve a large commercial customer that also has a demand meter. This type of difference is accounted for in the weighted customer allocation factors.

Direct Assignment
Some costs can be directly assigned to certain customer classes without being classified as demand-, energy-, or customer-related. These are generally costs associated with specific services, such as dedicated capital facilities, or with specific customer classes, such as lighting customers. Direct

City of Corona – 2024 Electric Utility Greenfield Rate Study 27 assignments include costs incurred to maintain and serve city-owned streetlights. The City of Corona does not have any expenses that are directly assignable.

Table 24 shows the functionalized and classified revenue requirement for FY 2025.

Table 24. Functionalized and Classified Revenue Requirement FY 2025 Function: Production Distribution
Classification: Demand Energy Demand Energy Customer
Purchased Power $1,912,821 $8,888,404 $0 $0 $0
Distribution O&M $0 $0 $505,074 $0 $0
Customer Service, Accounts & Sales $0 $185,000 $331,145 $0 $156,493 Admin & General $0 $268,990 $1,239,433 $0 $229,871
Taxes (Franchise Fee) $0 $0 $194,537 $0 $19,235
Interest & Debt Service $0 $0 $217,402 $0 $21,496
Other Contributions $0 -$1,743,483 $1,262,743 $0 $56,308 Capital Projects Funded from Rates $0 $0 $737,118 $0 $72,882 Other Revenues $0 -$3,020,508 -$720,600 $0 -$125,779
Total $1,912,821 $4,578,402 $3,766,850 $0 $430,506
Similar to the revenue requirement, Table 25 shows the functionalized and classified rate base for FY 2023.

Table 25. Functionalized and Classified Rate Base FY 2023 Distribution
Demand Energy Customer
Distribution Plant $13,640,101 $0 $1,348,665
General Plant $225,877 $0 $22,334
Accumulated Depreciation $8,244,323 $0 $815,157
Total $5,621,655 $0 $555,841

4.5 Allocation of Costs
The third step in performing a cost of service analysis is the allocation of the utility’s total functionalized and classified revenue requirement to the customer classes of service. This is performed through the application of an appropriate allocation methodology.

City of Corona – 2024 Electric Utility Greenfield Rate Study 28 City of Corona Allocation Methodology
The following are the specific allocation methods used in the City’s electric COSA.  Demand Allocation Factors. For purposes of this study, two types of demand allocation factors were developed.
o Non-coincident peak demand allocation factor (NCP). First, a non-coincident peak demand allocation factor was developed for each customer class. Expenses classified and allocated by the non-coincident peak demand allocation factor included those predicated on maximum demands such as distribution substations, and a portion of poles and lines, mains, meters and services. The NCP demand method allocates costs to each class of service based upon their highest individual non-coincident peak demand regardless of the time of occurrence. The NCP allocation factor is used to allocate distribution.
o Sum of monthly coincident peak (12 CP). A contribution to monthly system coincident peaks was derived from the non-coincident peak by use of a coincidence factor. This coincident peak demand allocation method is referred to as the sum of the monthly coincident peak (12 CP) method. The 12 CP method allocates demand costs on the basis of demand value at the time of the system peak demand in each month by each class. As discussed previously, the 12 CP method is used for power supply costs and transmission costs.
 Energy Allocation Factors. Energy costs vary directly with consumption. Accordingly, energy allocation factors were based upon electricity sales for each class. Energy allocation factors were used to allocate power supply costs, green-energy related costs and revenues and surplus sales revenue.
 Customer Allocation Factors. Two basic types of customer costs were identified – actual and weighted. The allocation factor for actual customers was derived from the actual number of customers served in each class of service. Two weighted customer allocation factors were also developed. The first weighted customer allocation factor considered the relative differences among the various customer classes of meter costs. The second weighted customer allocation factor considered the cost of customer accounting and meter reading by each rate class.

Customer allocation factors were used to allocate some distribution costs such as meters and meter installations, and costs associated with customer service, accounts and sales.  Rate Base Allocation. The value of the City’s electric system was estimated as of FY 2023 and is functionalized, classified and then allocated to customer classes. The resulting functionalized,

City of Corona – 2024 Electric Utility Greenfield Rate Study 29 classified and allocated rate base is then used to develop rate base allocation factors. These allocation factors (i.e., general plant, net plant, distribution rate base, etc.) are then used to allocate revenue requirement expenses. For example, maintenance of station equipment can be allocated using station equipment rate base, or property taxes might be allocated using net plant.  Other Cost Allocation. Other costs are allocated based on specific rate base items, O&M function totals, revenues, labor ratios and other allocation factors. These other allocation factors were used to allocate administrative and general expense items, as well as some other revenues such as dividend income or non-operating rental income.
 Administrative and General (A&G). All costs that are related to general overhead are classified to this area. Costs are allocated to customers based on their percentage of all other O&M expenses without power supply.
 Miscellaneous/Other Revenues. Miscellaneous/other revenues are generally allocated to customers based on allocation of all other O&M expenses.

The rate base allocation is shown in Table 26. The table summarizes how each rate class uses the distribution system based on their relative share of demand and size of services and meters.

Table 27 summarizes the load data used for customer class allocations.

Table 28 shows the allocated revenue requirement. Lastly, Table 29 summarizes the COSA results and indicated rate adjustments. These rate adjustments are the basis for the recommended rebalancing proposal for the rate design provided in the next section.

City of Corona – 2024 Electric Utility Greenfield Rate Study 30 Table 26. Functionalized, Classified, and Allocated Rate Base FY 2023 Total Residential
(D) GS-1 GS-2 TOU-GS-3 TOU-8 PA Lighting
Distribution
Demand $5,621,655 $606,258 $462,142 $1,953,686 $693,333 $1,621,569 $218,063 $66,605 Energy $0 $0 $0 $0 $0 $0 $0 $0
Customer $555,841 $275,671 $155,571 $100,208 $6,550 $16,990 $850 $0 Direct Assignment $0 $0 $0 $0 $0 $0 $0 $0
Total Cost / Classifier $6,177,496 $881,929 $617,713 $2,053,894 $699,883 $1,638,559 $218,913 $66,605 Table 27. Summary of FY 2025 Load Data
Total Residential
(D) GS-1 GS-2 TOU-GS-3 TOU-8 PA Lighting
Forecast Load Data
Energy Sales (kWh) 80,579,364 7,799,088 4,947,100 21,917,230 10,143,439 32,132,199 2,815,310 824,999 Total Billing Capacity (kW) 189,895 0 0 78,309 26,422 78,770 6,394 0 Avg. Monthly Billing Capacity (kW) 15,825 0 0 6,526 2,202 6,564 533 0 Number of Customers 1,939 1,323 373 160 8 10 2 62
Ratio of NCP to Avg. Billing 375% 0% 0% 84% 90% 95% 106% 0% Rate Classes NCP Demand at Meter 17,495 1,784 1,281 5,480 1,971 6,238 565 175 Forecast Based on Recorded and Forecast Data
Annual NCP Load Factor 53% 50% 44% 46% 59% 59% 57% 54%
Rate Classes CP Demand at Input Voltage 15,993 1,636 1,281 4,912 1,970 5,460 565 168 Annual CP Load Factor 53% 54% 44% 51% 59% 67% 57% 56%

City of Corona – 2024 Electric Utility Greenfield Rate Study 31 Table 28. Allocated Revenue Requirement FY 2025
Functional Cost
Classification
Total Cost
Residential
(D) GS-1 GS-2 TOU-GS-3 TOU-8 PA Lighting
Production
Demand (PD) $1,912,821 $159,868 $129,445 $647,349 $218,930 $654,270 $80,165 $22,794 Energy (PE) $4,578,402 $447,415 $285,148 $1,254,070 $578,881 $1,806,893 $159,301 $46,695 Distribution
Demand (DD) $3,766,850 $412,438 $309,729 $1,232,601 $462,666 $1,186,613 $124,890 $37,912 Energy (DE) $0 $0 $0 $0 $0 $0 $0 $0
Customer (DC) $430,506 $252,492 $93,928 $67,587 $4,649 $9,415 $469 $1,968 Total $10,688,580 $1,272,213 $818,250 $3,201,607 $1,265,127 $3,657,192 $364,825 $109,368 The retail rate increase of 2% would apply if the City were to increase rates on July 1, 2024. Since the City plans to adjust rates on January 1, 2025, the rate adjustment is 4%. This rate adjustment would collect revenues that meet forecasted FY 2025 costs.

Table 29. Total of Operating Functional Categories Allocated to Cost Components Total
Residential
(D) GS-1 GS-2 TOU-GS-3 TOU-8 PA Lighting
Revenues - Present Rate $10,479,000 $1,238,485 $905,310 $3,189,352 $1,341,516 $3,479,186 $250,567 $74,583 Less Allocated Revenue Requirement $10,688,580 $1,272,213 $818,250 $3,201,607 $1,265,127 $3,657,192 $364,825 $109,368 Difference -$209,580 -$33,727 $87,061 -$12,255 $76,389 -$178,006 -$114,258 -$34,785 Revenue To Cost Ratio 98.0% 97.3% 110.6% 99.6% 106.0% 95.1% 68.7% 68.2% % Increase Retail Rates to Equal Allocated
Cost 2.00% 2.7% -9.6% 0.4% -5.7% 5.1% 45.6% 46.6%

City of Corona – 2024 Electric Utility Greenfield Rate Study 32 5 ELECTRIC RATE DESIGN
EES proposes the following adjustments to the Greenfield rate structures:
 Adjusting rates annually by the recommended revenue adjustments of 4.0 percent per year.  Rebalance customer class rate levels to recover the rate class cost of service. These adjustments may result in rate adjustments that differ from the total 4.0 percent adjustment.  Increasing the fixed proportion of rate collection to align with COSA results.  Removing the highest cost tier to simplify the rate structure.  Separate the PBC from base rates to improve transparency.  Remove seasonal difference from energy rates.
 Implement a Specific rate for commercial electric vehicle charging stations.  Recover power supply-related demand costs throughout the year rather than just summer peak periods.
 Rebalance customer class revenue collection based on COSA results.

The rebalancing proposal is provided in Table 30 below. The proposed adjustment to the pumping and agriculture class is recommended to be implemented over an 18-month period. This longer period will allow existing customers to adjust their usage patterns to avoid large bill impacts.

Table 30. Recommended Rebalancing Proposal
Total Residential
D
Small
Commercial
GS-1
Medium
Commercial
GS-2
Large
Commercial
GS-3
Industrial
TOU-8
Pumping &
Agriculture
PA
Lighting
Rate
Adjustment 4.0% 4.0% -2.3% 1.6% -2.9% 5.1% 57.9% 46.6%
Number of
Meters 1,938 1,323 373 160 8 10 2 62
The electric rates have up to four components: 1) a fixed monthly service charge 2) volumetric rates, (3) demand charges, (4) Power Factor Adjustment, and (5) Public Benefits Charge. Customers must pay the fixed charge regardless of energy use or demand.

1. Fixed monthly service charge: The rates are established based on the size of the meter at the property receiving electric service and are calculated to recover a portion of the City’s fixed costs, such as meter reading and customer service.

City of Corona – 2024 Electric Utility Greenfield Rate Study 33

2. Variable rates: The rates are calculated based on the cost of wholesale electricity and transmission. The remaining fixed costs that are not recovered via fixed charges (fixed or demand charges) such as the cost of maintaining the electric distribution system, are also recovered from variable charges. The rates are billed per kWh.

3. Demand Charge For demand-metered customers, demand charges recover the cost of demandrelated power supply expenses and the cost of maintaining the electric distribution system. These charges are billed each month based on maximum kW.

4. Power Factor Adjustment: The power factor adjustment recovers the cost of inefficient use of power on the customer side of the meter. The power factor is the ratio of real power to apparent power. The power factor adjustment is billed per kVa.

5. Public Benefits Charge: In 1996, the State of California required all publicly owned electric utilities to establish a charge for programs that would benefit the public such as low-income assistance, energy efficiency, and renewable resources. The Public Benefits Charge (PBC) is equal to 2.85% of the utility’s annual revenue requirement.

Combining the rates and billing determinants for each customer results in monthly bills and annual revenue consistent with the cost of providing electric service. Each subsection below provides the unit COSA results, current rates, and proposed rates. The proposed rates are developed consistent with COSA unit costs to improve interclass equity.

5.1 Recommended Residential Rates
The proposed residential rates, as shown in Table 31, increase the fixed charge based on the COSA results (unit costs in column 1). The fixed charge is recommended for both single family and multifamily accounts as the cost of meter reading and billing is similar for both types of dwellings. The energy rate is reduced to account for the increase in fixed charge and the separation of the PBC (currently $0.00378/kWh based on 2.85% of the total revenue requirement). Additionally, the energy rate structure is simplified from 4 tiers down to 3 tiers. Most usage (64.2%) is in the Tier 1 baseline followed by 11.2% in Tier 2 and 24.6% in the new Tier 3. Maintaining the tiers encourages efficient use of electricity while not penalizing customers who adopt electric vehicles. Once the planned metering infrastructure is in place, it is recommended to re-evaluate the rate design to consider time-of-use rates which best represent the marginal cost of power supply for all customers.

City of Corona – 2024 Electric Utility Greenfield Rate Study 34 Table 31. Residential: COSA Unit Costs, Current Rates, and Recommended FY 2025 Rates Cost of
Service Unit
Costs
Current Rates Recommended
FY 2025
Fixed Charge, $/month $15.90 Single Family: $0.88/day
Multi-Family: $0.67/day
$15.90
Energy, $/kWh $0.1273
Tier 1 Baseline $0.11808 $0.10100
Tier 2 101-130% Baseline $0.13741 $0.11100
Tier 3 131-200% Baseline $0.22696 $0.21000
Tier 4 over 200% Baseline $0.32337
Public Benefits Charge $/kWh Included in energy rate. $0.00378

5.2 Recommended Small Commercial (GS-1) Rates
The recommended small commercial rates increase the fixed charge based on the COSA results (unit costs in column 1) and shown in Table 32. The energy rate is reduced to account for the increase in fixed charge and the separation of the PBC (currently $0.00378/kWh). Additionally, the energy rate structure is simplified so that the rate is the same year-round instead of the differential between summer and winter.

When reviewing seasonal power costs, we found that there was no significant difference in costs between summer and winter. The COSA unit costs separate demand and energy costs. Because this class is not demand-metered, the demand costs are recovered through the variable energy rate proposed.

Table 32. GS-1: COSA Unit Costs, Current Rates, and Recommended FY 2025 Rates Cost of Service
Unit Costs Current Rates RecommendedFY 2025
Fixed Charge, $/month $20.97 Single Phase: $12.99
Three Phase: $3.16
Single Phase: $20.97
Three Phase: $3.16
Demand, $/kW $27.82
Energy, $/kWh $0.058
Summer $0.17280 $0.15500
Winter $0.16872 $0.15500
Public Benefits Charge, $/kWh Included in energy rate. $0.00378 Total Variable Rate $0.17024 $0.15878
The removal of the seasonal energy rate increases bills during the winter but reduces summer bills for GS-1 customers. Table 33 below shows examples of customer bill impacts including average seasonal use.

City of Corona – 2024 Electric Utility Greenfield Rate Study 35 Table 33. GS-1: Bill Impact Example
Customer Current Bill Recommended FY
2025 $ Change
Average Summer Use, 1,100 kWh Summer $203.10 $191.53 -$11.57 Average Winter Use, 700 kWh Winter $131.14 $129.53 -$1.60 Dental Office, 400 kWh Winter $80.51 $83.03 $2.52
Construction Retailer, 3,280 kWh Summer $579.81 $529.43 -$50.35

5.3 Recommended Medium Commercial (GS-2) Rates
The recommended Medium Commercial rates decrease the fixed charge based on the COSA results (unit costs in column 1) and shown in Table 34. The energy rate is reduced to account for the separation of the PBC (currently $0.00378/kWh) and increase in demand rates. Additionally, the energy rate structure is simplified so that the rate is the same year-round instead of the differential between summer and winter. When reviewing seasonal power costs, we found that there was no significant difference in costs between summer and winter energy costs. The demand rate is adjusted so that power supply demand-related costs are collected year-round consistent with how the utility is billed for power supply.

The facilities charge is increased to recover the fixed costs of the distribution. The power supply demand rate recovers the power supply related expenses incurred throughout the year.

Table 34. GS-2: COSA Unit Costs, Current Rates, and Recommended FY 2025 Rates Cost of Service
Unit Costs Current Rates Recommended FY 2025
Fixed Charge, $/month $35.13 $71.50 $35.13
Demand, $/kW
Power Supply $8.27 Summer Peak:(1) $20.67 Peak: (2) $8.27 Distribution $15.74 Facilities: $7.35 Facilities: $15.74 Energy, $/kWh $0.057
Summer $0.09648 $0.05905
Winter $0.08738 $0.05905
Public Benefits Charge Included in energy rate. $0.00378 Total Variable Rate $0.09087 $0.06283

1. Summer Peak is from 4 pm to 9 pm on weekdays during summer months

2. Peak from 4 pm to 9 pm year-round
The removal of the seasonal energy rate increases bills during the winter but reduces summer bills for GS-2 customers. Table 35 below shows examples of customer bill impacts from actual billing data.

City of Corona – 2024 Electric Utility Greenfield Rate Study 36 Table 35. GS-2: Bill Impact Example
kWh kW Current Recommended
FY 2025 Difference
Summer
Medium/Large Retail 10,510 35.3 $1,930.56 $1,479.08 -$451.48 Hotel 58,800 197.6 $10,800.83 $8,274.94 -$2,525.89
Bank 6,700 23.7 $1,261.46 $970.36 -$291.10
Winter
Medium/Large Retail 7,100 23.9 $795.75 $999.19 $203.43
Hotel 54,000 181.5 $6,052.19 $7,599.44 $1,547.25
Bank 4,800 18.4 $554.91 $728.92 $174.01

5.4 Recommended Large Commercial (TOU-GS-3) Rates
The recommended Large Commercial rates decrease the fixed charge based on the COSA results (unit costs in column 1), and shown in Table 36. The energy rate is reduced to account for the separation of the PBC (currently $0.00378/kWh) and increase in demand rates. Additionally, the energy rate structure is simplified so that the rate is the same year-round instead of the differential between summer and winter.

When reviewing seasonal power costs, we found that there was no significant difference in costs between summer and winter energy costs. The demand rate is adjusted so that power supply demand-related costs are collected year-round consistent with how the utility is billed for power supply. The facilities charge is increased to recover the fixed costs of the distribution. The power supply demand rate recovers the power supply related expenses incurred throughout the year. The time of use energy rates reflect the actual power costs weighted according to the marginal cost of power supply during the respective billing periods.

City of Corona – 2024 Electric Utility Greenfield Rate Study 37 Table 36. TOU-GS-3: COSA Unit Costs, Current Rates, and Recommended FY 2025 Rates

1. Summer Peak is from 4 pm to 9 pm on weekdays during summer months

2. Mid-Peak is 4 pm to 9 pm on summer weekends except holidays and 4 pm to 9 pm winter weekdays, except holidays

3. Peak is from 4 pm to 9 pm year-round
The removal of the seasonal energy rate increases bills during the winter but reduces summer bills for GS-3 customers. Table 37 below shows examples of customer bill impacts from actual billing data. Note that there are 8 winter months and 4 summer months.

Table 37. TOU-GS-3: Bill Impact Example
kWh kW Current Recommended
FY 2025 Difference
Summer 58,953 181 $12,126.56 $9,165.12 -$2,961.44
Winter 41,967 96 $4,998.16 $5,392.00 $393.84

5.5 Recommended Industrial (TOU-8) Rates
The recommended Industrial rates decrease the fixed charge based on the COSA results (unit costs in column 1), as shown in Tables 38 and 39. The energy rate is reduced to account for the separation of the PBC (currently $0.00378/kWh) and increase in demand rates. The demand rate is adjusted so that power supply demand-related costs are collected year-round consistent with how the utility is billed for power supply. The facilities charge is increased to recover the fixed costs of the distribution. The power supply demand rate recovers the power supply related expenses incurred throughout the year. The time of use energy rates reflect the actual power costs weighted according to the marginal cost of power supply during the respective billing periods. This marginal cost pricing methodology is considered best practice in time of use rate-making for electric utilities.

Cost of Service
Unit Costs Current Rates Recommended FY 2025
Fixed Charge, $/month $49.30 $277.25 $49.30
Demand, $/kW
Power Supply $8.29 Summer Peak:(1) $18.16
Mid-Peak:(2) $6.23
Peak:(3) $8.29
Distribution $17.51 Facilities: $7.62 Facilities: $17.51 Energy, $/kWh $0.057
Summer On-Peak $0.13561 $0.09620
Summer Mid-Peak $0.11027 $0.07280
Summer Off-Peak $0.07706 $0.05200
Winter Mid-Peak $0.11282 $0.07986
Winter Off-Peak $0.08052 $0.05200
Power Factor Adjustment, $/kVa $0.18 $0.18
Public Benefits Charge, $/kWh Included in energy rate. $0.00378

City of Corona – 2024 Electric Utility Greenfield Rate Study 38 Table 38. TOU-8: COSA Unit Costs, Current Rates, and Recommended FY 2025 Rates COSA Unit Costs Current Rates Recommended FY 2025
Fixed Charge, $/month $76.97 $346 $76.97
Demand, $/kW
Power Supply $8.31 Summer Peak: (1) $16.91
Mid-Peak: (2) $5.71
Peak: (3) $8.31
Distribution $15.06 Facilities: $8.31 Facilities: $15.06 Energy, $/kWh $0.056
Summer On-Peak $0.12675 $0.09630
Summer Mid-Peak $0.10299 $0.07319
Summer Off-Peak $0.07184 $0.05200
Winter Mid-Peak $0.10538 $0.07986
Winter Off-Peak $0.07509 $0.05200
Power Factor Adjustment, $/kVa $0.18 $0.18
Public Benefits Charge, $/kWh Included in energy rate. $0.00378

1. Summer Peak is from 4 pm to 9 pm on weekdays during summer months

2. Mid-Peak is 4 pm to 9 pm on summer weekends except holidays and 4 pm to 9 pm winter weekdays except holidays

3. Peak is from 4 pm to 9 pm year-round
Table 39. TOU-8: Bill Impact Example
Customer B kWh kW Current Recommended
FY 2025 Difference
Summer 101,087 343 $19,889.12 $15,154.10 -$4,735.02
Winter 91,675 225 $9,986.80 $11,265.28 $1,278.48

5.6 Recommended Pumping and Agriculture (TOU-PA-2) Rates The recommended pumping and agriculture rates decrease the fixed charge based on the COSA results (unit costs in column 1). The energy rate is reduced to account for the separation of the PBC (currently $0.00378/kWh) and increase in demand rates. The demand rate is adjusted so that power supply demand-related costs are collected year-round consistent with how the utility is billed for power supply.

The facilities charge is increased to recover the fixed costs of the distribution. The power supply demand rate recovers the power supply related expenses incurred throughout the year. The time of use energy rates reflect the actual power costs weighted according to the marginal cost of power supply during the respective billing periods. Table 40 below shows the rate adjustment planned over the 18-month phasein period. The increase in the PBC in January of 2026 is due to the increase in revenue requirement in that year. Similarly, the fixed charge in January 2026 aligns with the fixed charge calculated by the COSA for FY 2026.

City of Corona – 2024 Electric Utility Greenfield Rate Study 39 Table 40. TOU-PA-2: COSA Unit Costs, Current Rates, and Recommended FY 2025 Rates FY2025
COSA Unit
Costs
Current Rates January 2025
Proposed
July 2025
Proposed
January 2026
Proposed
Fixed Charge, $/month $19.14 $63.25 $19.14 $19.14 $20.86 Demand, $/kW
Power Supply $12.54 Summer Peak:(1)
$10.85
Peak: (2) $6.00 Peak: $12.00 Peak: $12.98
Distribution $19.53 Facilities: $3.85 Facilities: $8.00 Facilities: $10.00 Facilities: $21.55 Energy, $/kWh $0.057
Summer On-Peak $0.13064 $0.10361 $0.10361 $0.09444
Summer Mid-Peak $0.10929 $0.07874 $0.07874 $0.07178
Summer Off-Peak $0.05226 $0.05595 $0.05595 $0.05100
Winter Mid-Peak $0.12255 $0.08592 $0.08592 $0.07832
Winter Off-Peak $0.05226 $0.05595 $0.05595 $0.05100
Power Factor Adjustment, $/kVa $0.18 $0.18 $0.18 $0.18720 Public Benefits Charge $/kWh Included in
energy rate.
$0.00378 $0.00378 $0.00405

1. Summer Peak is from 4 pm to 9 pm on weekdays during summer months

2. Peak is from 4 pm to 9 pm year-round

40 City of Corona – 2024 Electric Utility Greenfield Rate Study

5.7 Recommended Lighting Rates
The current rate structure for each of the lighting schedules is updated based on the COSA results indicating a needed rate increase of approximately 47%. In order to develop new rate design for this class, a detailed lighting study would be needed as shown in Table 41.

Table 41. Lighting: Current Rates and Recommended FY 2025 Rates Current Rates Proposed FY 2025
Outdoor Area Lighting (AL-2)
Energy Charge, $/kWh $0.08224 $0.11678
Public Benefits Charge $/kWh Included in Energy Rate $0.00378 Customer Charge, $/month $7.00 $10.26
Street Lighting (LS-3)
Energy Charge, $/kWh $0.08224 $0.11678
Public Benefits Charge $/kWh Included in Energy Rate $0.00378 Customer Charge, $/month $7.00 $10.26
Traffic Control (TC-1)
Energy Charge, $/kWh $0.11407 $0.16345
Public Benefits Charge $/kWh Included in Energy Rate $0.00378 Customer Charge, $/month $9.49 $13.91
Three Phase, $/month $3.16 $4.64

5.8 Recommended Commercial Electric Vehicle Charging Rates Current commercial EV charging stations are being served at the TOU-8 rate schedule, as shown in Table 42. The TOU-8 rate schedule more appropriately applies to services with high load factors, however, EV charging stations typically have very low load factors, often below 20%. These low load factors are associated with higher costs to serve. Therefore, it is recommended that a special EV charging rate be implemented so that the cost of service for these customers is not being shared with other rate classes. The recommended rate below takes the fixed charge and facilities charge from the TOU-8 rate schedule. Power-supply related demand costs are recovered through the recommended energy rates.

The on-peak and off-peak period energy rates provide incentives to customers to use the charging stations during off-peak periods.

41 City of Corona – 2024 Electric Utility Greenfield Rate Study Table 42. EV Charging: Recommended FY 2025 Rates
Recommended FY 2025 Rates
Fixed Charge, $/month $76.97
Demand (Facilities), $/kW $15.06
Energy, $/kWh
On-Peak 4-9 pm $0.19710
Off-Peak All Other Hours $0.06570
Power Factor Adjustment, $/kVa $0.18
Public Benefits Charge $/kWh $0.00378
Figure 6 compares the recommended EV Charging rate for the City with current EV charging rates offered by SCE.

Figure 6. EV Charging Rate Comparison with SCE
Once the utility has collected usage data for this new class, it is recommended that the rate analysis be updated for the specific usage patterns at city-served charging stations. $0.00
$0.05
$0.10
$0.15
$0.20
$0.25
$0.30
$0.35
SCE EV-8 20-500kW SCE EV-9 >500kW PRI Corona EV Rate
$/kWh

42 City of Corona – 2024 Electric Utility Greenfield Rate Study

APPENDIX
Rate Current Rate FY25
Proposed
FY26
Proposed
FY27
Proposed
FY28
Proposed
FY29
Proposed
Residential
Fixed Charge, $/month Single Family $0.88
Multi-Family $0.67
$15.90 $16.54 $17.20 $17.89 $18.61
Energy $/kWh Tier 1 Baseline $0.11808 $0.10100 $0.10504 $0.10924 $0.11361 $0.11815 Energy $/kWh Tier 2 101-130% Baseline $0.13741 $0.11100 $0.11544 $0.12006 $0.12486 $0.12985 Energy $/kWh Tier 3 131-200% Baseline $0.22696 $0.21000 $0.21840 $0.22714 $0.23623 $0.24568 Energy $/kWh Tier 4 over 200% Baseline $0.32337
Public Benefits Charge $/kWh Incl. in rates $0.00378 $0.00405 $0.00419 $0.00433 $0.00448 Small Commercial GS-1
Fixed Charge, $/month Single Phase $12.99 $20.97 $21.81 $22.68 $23.59 $24.53 Fixed Charge, $/month Three Phase* $3.16 $3.16 $3.29 $3.42 $3.56 $3.70 Energy $/kWh Summer $0.17280 $0.155000 $0.161200 $0.167650 $0.174360 $0.181330 Energy $/kWh Winter $0.16872
Public Benefits Charge $/kWh Incl. in rates $0.00378 $0.00405 $0.00419 $0.00433 $0.00448 *Note: total cost for Three Phase customer will include Single Phase rate plus Three Phase rate.

Medium Commercial GS-2
Fixed Charge, $/month $71.50 $35.13 $36.54 $38.00 $39.52 $41.10 Demand $/kW Power Supply (Peak)** Summer Peak $20.67 $8.27 $8.60 $8.94 $9.30 $9.67 Demand $/kW Distribution (Facilities) $7.35 $15.74 $16.37 $17.02 $17.70 $18.41 Energy $/kWh Summer $0.09648 $0.05905 $0.06141 $0.06387 $0.06642 $0.06908 Energy $/kWh Winter $0.08738
Public Benefits Charge $/kWh Incl. in rates $0.00378 $0.00405 $0.00419 $0.00433 $0.00448 **Summer Peak is used for current rates: 4-9 pm during summer months. Peak will be used for proposed rates: 4-9 pm yearround.

Large Commercial TOU-GS-3
Fixed Charge, $/month $277.25 $49.30 $51.27 $53.32 $55.45 $57.67