TITLE 20. PUBLIC UTILITIES AND TELECOMMUNICATIONS

STATE CORPORATION COMMISSION

Proposed Regulation

Title of Regulation: 20VAC5-315. Regulations Governing Net Energy Metering (amending 20VAC5-315-20; adding 20VAC5-315-100).

Statutory Authority: §§ 12.1-13 and 56-594 of the Code of Virginia.

Public Hearing Information: A public hearing will be held upon request.

Public Comment Deadline: April 20, 2026.

Agency Contact: Mike Cizenski, Deputy Director, Division of Public Utility Regulation, State Corporation Commission, P.O. Box 1197, Richmond, VA 23218, telephone (804) 371-9441, or email mike.cizenski@scc.virginia.gov.

Summary:

Pursuant to Chapters 615 and 658 of the 2025 Acts of Assembly, the proposed amendments implement a distribution cost sharing program that allocates the costs of distribution system upgrades needed to interconnect new projects, among participating net energy metering projects sized between 250 kilowatts and less than or equal to three megawatts, with requirements for Phase I and Phase II Utilities for cost recovery, refunds, and exemptions if a developer of a project pays for such program in full.

AT RICHMOND, FEBRUARY 17, 2026

COMMONWEALTH OF VIRGINIA, ex rel.

STATE CORPORATION COMMISSION

CASE NO. PUR-2026-00002

Ex Parte: In the matter concerning a rulemaking

proceeding required by Chapters 615 and 658

of the 2025 Acts of Assembly

ORDER FOR NOTICE AND COMMENT

The Virginia General Assembly enacted legislation during its 2025 Session¹ requiring the State Corporation Commission (Commission) to establish by regulation a distribution cost sharing program for Phase I and Phase II Utilities, as those terms are defined in subdivision A 1 of § 56-585.1 of the Code of Virginia (Code), to construct distribution upgrades required to interconnect triggering projects.² The new rules shall be finalized by the Commission no later than July 1, 2026.

Under the program:

[w]hen a Phase I or Phase II Utility determines that a qualifying upgrade is required to interconnect a triggering project, such utility shall determine the costs of the qualifying upgrade and the net increase in hosting capacity that would result from the construction of the qualifying upgrade. The costs of the qualifying upgrade shall be subject to approval by the Commission that the costs are reasonable and prudent. The program shall require each Phase I and Phase II Utility to allocate the costs of qualifying upgrades among any sharing projects based on the AC nameplate capacity rating of each sharing project, except that a project shall be exempted from the program if the owner or developer of such project elects to pay in full the approved cost of any associated qualifying upgrade. The Commission shall determine limits on cost recovery for ratepayers and the appropriate time period for cost recovery under the program. The program shall also require that the costs attributed to jurisdictional triggering projects are recovered from jurisdictional sharing projects and costs attributed to nonjurisdictional triggering projects are recovered from nonjurisdictional sharing projects. The Commission may establish a system to refund projects for any interconnection upgrade costs collected during time periods in which such projects are not operational and may provide such refunds upon the petition of the owner of a participating project.³

NOW THE COMMISSION, upon consideration of the foregoing, is of the opinion and finds that a proceeding should be established to promulgate rules establishing a distribution cost sharing program for Phase I and Phase II Utilities. To initiate this proceeding, the Commission's Staff (Staff) has prepared proposed rules which are appended to this Order (Proposed Rules) as Attachment A. We will direct that notice of the Proposed Rules be given to the public and that interested persons be provided an opportunity to file written comments on, propose modifications or supplements to, or request a hearing on the Proposed Rules. We find that Staff should be directed to report on or respond to any comments, proposals, or requests for hearing submitted to the Commission on the Proposed Rules. We further find that a copy of the Proposed Rules should be sent to the Registrar of Regulations for publication in the Virginia Register of Regulations.

Accordingly, IT IS ORDERED THAT:

(1) This matter is docketed as Case No. PUR-2026-00002.

(2) All comments or other documents and pleadings filed in this matter shall be submitted electronically to the extent authorized by Rule 5VAC5-20-150, Copies and format, of the Commission's Rules of Practice and Procedure⁴ (Rules of Practice). Confidential and Extraordinarily Sensitive Information shall not be submitted electronically and shall comply with Rule 5VAC5-20-170, Confidential information, of the Rules of Practice. Any person seeking to hand deliver and physically file or submit any pleading or other document shall contact the Clerk's Office Document Control Center at (804) 371-9838 to arrange the delivery.

(3) Pursuant to 5VAC5-20-140, Filing and service, of the Rules of Practice, the Commission directs that service on participants and Staff in this matter shall be accomplished by electronic means. Concerning Confidential or Extraordinarily Sensitive Information, participants and Staff are instructed to work together to agree upon the manner in which documents containing such information shall be served upon one another, to the extent practicable, in an electronically protected manner, even if such information is unable to be filed in the Office of the Clerk, so that no participant or Staff is impeded from participating in this matter.

(4) On or before April 20, 2026, any interested person may file comments on the Proposed Rules by following the instructions found on the Commission's website: scc.virginia.gov/case-information/submit-public-comments. Those unable, as a practical manner, to file comments electronically may file such comments by U.S. mail to the Clerk of the State Corporation Commission, c/o Document Control Center, P.O. Box 2118, Richmond, Virginia 23218-2118. All comments shall refer to Case No. PUR-2026-00002. Individuals should be specific in their comments on the Proposed Rules.

(5) On or before May 11, 2026, Staff shall file with the Clerk of the Commission its report on or response to any comments, proposals, or requests for hearing submitted to the Commission on the Proposed Rules.

(6) An electronic copy of the Proposed Rules may be obtained by submitting a request to Mike Cizenski, Deputy Director in the Commission's Division of Public Utility Regulation at the following email address: mike.cizenski@scc.virginia.gov. An electronic copy of the Proposed Rules can also be found on the Division of Public Utility Regulation's website: scc.virginia.gov/regulated-industries/utility-regulation/pur-responsibilities/rulemaking. Interested persons may also download unofficial copies of this Order and the Proposed Rules from the Commission's website: scc.virginia.gov/case-information.

(7) Within 10 business days hereof, Staff shall provide copies of this Order by electronic transmission, or when electronic transmission is not possible, by mail, to individuals, organizations, and companies who have been identified by Staff as potentially being interested in this proceeding and the Proposed Rules.

(8) The Commission's Office of General Counsel shall forward a copy of this Order and the Proposed Rules to the Registrar of Regulations for publication in the Virginia Register of Regulations.

(9) The Director of the Commission's Division of Information Resources promptly shall post a copy of this Order on the Commission's website.

(10) Any documents filed in paper form with the Office of the Clerk of the Commission in this docket may use both sides of the paper. In all other respects, except as modified herein, all filings shall comply fully with the requirements of 5VAC5-20-150, Copies and format, of the Commission's Rules of Practice.

(11) This matter is continued.

A COPY hereof shall be sent electronically by the Clerk of the Commission to all persons on the official Service List in this matter. The Service List is available from the Clerk of the Commission.

_____________________________

20VAC5-315-20. Definitions.

The following words and terms when used in this chapter shall have the following meanings unless the context clearly indicates otherwise:

"Agricultural business" means any sole proprietorship, corporation, partnership, electing small business (Subchapter S) corporation, or limited liability company engaged primarily in the production and sale of plants and animals, products collected from plants and animals, or plant and animal services that are useful to the public.

"Agricultural net metering customer" means a customer that operates an electrical generating facility consisting of one or more agricultural renewable fuel generators having an aggregate generation capacity of not more than 500 kilowatts as part of an agricultural business under a net metering service arrangement. An agricultural net metering customer may be served by multiple meters serving the agricultural net metering customer that are located at the same or adjacent sites and that may be aggregated into one account. This account shall be served under the appropriate tariff.

"Agricultural renewable fuel generator" or "agricultural renewable fuel generating facility" means one or more electrical generators that:

1. Use as their sole energy source solar power, wind power, or aerobic or anaerobic digester gas;

2. The agricultural net metering customer owns and operates, or has contracted with other persons to own or operate, or both;

3. Are located on land owned or controlled by the agricultural business;

4. Are connected to the agricultural net metering customer's wiring on the agricultural net metering customer's side of the agricultural net metering customer's interconnection with the distributor;

5. Are interconnected and operated in parallel with an electric company's distribution facilities; and

6. Are used primarily to provide energy to metered accounts of the agricultural business.

"Billing period" means, as to a particular agricultural net metering customer or a net metering customer, the time period between the two meter readings upon which the electric distribution company and the energy service provider calculate the agricultural net metering customer's or net metering customer's bills.

"Billing period credit" means, for a non-time-of-use agricultural net metering customer or a non-time-of-use net metering customer, the quantity of electricity generated and fed back into the electric grid by the agricultural net metering customer's agricultural renewable fuel generator or by the net metering customer's renewable fuel generator in excess of the electricity supplied to the customer over the billing period. For time-of-use agricultural net metering customers or time-of-use net metering customers, billing period credits are determined separately for each time-of-use tier.

"Competitive service provider" means a person, licensed by the State Corporation Commission, that sells or offers to sell a competitive energy service within the Commonwealth. This term includes affiliated competitive service providers but does not include a party that supplies electricity or natural gas, or both, exclusively for its own consumption or the consumption of one or more of its affiliates. For the purpose of this chapter, competitive service providers include aggregators.

"Contiguous sites" means a group of land parcels in which each parcel shares at least one boundary point with at least one other parcel in the group. Property whose surface is divided only by public right-of-way is considered contiguous.

"Customer" means a net metering customer or an agricultural net metering customer.

"Demand charge-based time-of-use tariff" means a retail tariff for electric supply service that has two or more time-of-use tiers for energy-based charges and an electricity supply demand (kilowatt) charge.

"Electric cooperative" means an electric distribution company organized pursuant to Chapter 9.1 (§ 56-231.15 et seq.) of Title 56 of the Code of Virginia, owned by its members.

"Electric distribution company" means the entity that owns or operates the distribution facilities delivering electricity to the premises of an agricultural net metering customer or a net metering customer.

"Energy service provider (supplier)" means the entity providing electricity supply service, either tariffed or competitive service, to an agricultural net metering customer or a net metering customer.

"Excess generation" means the amount of electrical energy generated in excess of the electrical energy consumed by the agricultural net metering customer or net metering customer over the course of the net metering period. For time-of-use agricultural net metering customers or net metering customers, excess generation is determined separately for each time-of-use tier.

"Generator" or "generating facility" means an electrical generating facility consisting of one or more renewable fuel generators or one or more agricultural renewable fuel generators that meet the criteria under the definition of "net metering customer" and "agricultural net metering customer," respectively.

"Hosting capacity" means the amount of aggregate generation that can be accommodated on the electric distribution system without any infrastructure upgrades.

"Low-income utility customer" means the same as that term is defined in § 56-576 of the Code of Virginia.

"Net metering customer" means, for an electric cooperative, a customer owning and operating, or contracting with other persons to own or operate, or both, an electrical generating facility consisting of one or more renewable fuel generators having an aggregate generation capacity of not more than 20 kilowatts for residential customers and not more than one megawatt for nonresidential customers. The generating facility shall be operated under a net metering service arrangement. For an investor-owned electric distribution company, "net metering customer" means a customer owning and operating, or contracting with other persons to own or operate, or both, an electrical generating facility consisting of one or more renewable fuel generators having an aggregate generation capacity of not more than 25 kilowatts for residential customers and not more than three megawatts for nonresidential customers. The generating facility shall be operated under a net metering service arrangement.

"Net metering period" means each successive 12-month period beginning with the first meter reading date following the final interconnection of an agricultural net metering customer or a net metering customer's generating facility consisting of one or more agricultural renewable fuel generators or one or more renewable fuel generators, respectively, with the electric distribution company's distribution facilities.

"Net metering service" means providing retail electric service to an agricultural net metering customer operating an agricultural renewable fuel generating facility or a net metering customer operating a renewable fuel generating facility and measuring the difference, over the net metering period, between the electricity supplied to the customer from the electric grid and the electricity generated and fed back to the electric grid by the customer.

"Nonprofit customer" or "not-for-profit customer" means a person that is exempt from federal income taxation, including (without limitation) schools, hospitals, institutions of higher education, public charities, and churches and other houses of religious worship, as determined by the Internal Revenue Service.

"Person" means any individual, sole proprietorship, corporation, limited liability company, partnership, association, company, business, trust, joint venture, or other private legal entity, the Commonwealth, or any city, county, town, authority, or other political subdivision of the Commonwealth.

"Phase I Utility" shall be defined in accordance with subdivision A 1 of § 56-585.1 of the Code of Virginia.

"Phase II Utility" shall be defined in accordance with subdivision A 1 of § 56-585.1 of the Code of Virginia.

"Program" means the distribution cost sharing program established pursuant to 20VAC5-315-100.

"Purchase power agreement provider" or "PPA provider" means, in an electric cooperative service territory, a person registered with the commission's Division of Public Utility Regulation pursuant to 20VAC5-315-77 to offer third-party partial requirements power purchase agreements to customers.

"Qualifying upgrade" means a system upgrade that increases the hosting capacity of the utility's distribution system.

"Registry" means, in reference to a PPA provider, the list of those persons registered with the commission's Division of Public Utility Regulation as PPA providers.

"Renewable Energy Certificate" or "REC" represents the renewable energy attributes associated with the production of one megawatt-hour (MWh) of electrical energy by a generator.

"Renewable fuel generator" or "renewable fuel generating facility" means one or more electrical generators that:

1. Use renewable energy, as defined by § 56-576 of the Code of Virginia, as their total fuel source;

2. The net metering customer owns and operates, or has contracted with other persons to own or operate, or both;

3. Are located on land owned or leased by the net metering customer and connected to the net metering customer's wiring on the net metering customer's side of its interconnection with the distributor;

4. Are interconnected pursuant to a net metering arrangement and operated in parallel with the electric distribution company's distribution facilities; and

5. Are intended primarily to offset all or part of the net metering customer's own electricity requirements. For an electric cooperative, the capacity of any generating facility installed on or after July 1, 2015, shall not exceed the expected annual energy consumption based on the previous 12 months of billing history or an annualized calculation of billing history if 12 months of billing history is not available. For an investor-owned electric distribution company, the capacity of any generating facility installed between July 1, 2015, and July 1, 2020, shall not exceed the expected annual energy consumption based on the previous 12 months of billing history or an annualized calculation of billing history if 12 months of billing history is not available.

"Sharing project" means any distributed energy resource with an alternating current (AC) nameplate capacity rating greater than or equal to 250 kilowatts and less than or equal to three megawatts within a Phase I or Phase II Utility's service territory seeking to interconnect to the utility's distribution system and participate in net energy metering pursuant to § 56-594 of the Code of Virginia that utilizes distribution system upgrades that were necessary to interconnect a triggering project.

"Small agricultural generating facility" means an electrical generating facility that:

1. Has a capacity of not more than 1.5 megawatts and does not exceed 150% of the customer's expected annual energy consumption based on the previous 12 months of billing history or an annualized calculation of billing history if 12 months of billing history is not available;

2. Uses as its total source of fuel renewable energy;

3. Is located on the customer's premises and is interconnected with the utility's distribution system through a separate meter;

4. Is interconnected and operated in parallel with an electric utility's distribution system but not transmission facilities;

5. Is designed so that the electricity generated is expected to remain on the utility's distribution system; and

6. Is a qualifying small power production facility pursuant to the Public Utility Regulatory Policies Act of 1978 (P.L. 95-617).

"Small agricultural generator" means a customer that:

1. Is not an eligible agricultural customer-generator pursuant to § 56-594 of the Code of Virginia;

2. Operates a small agricultural generating facility as part of (i) an agricultural business or (ii) any business granted a manufacturer license pursuant to subdivisions 1 through 6 of § 4.1-206.1 of the Code of Virginia;

3. May be served by multiple meters that are located at separate but contiguous sites;

4. May aggregate the electricity consumption measured by the meters, solely for purposes of calculating 150% of the customer's expected annual energy consumption but not for billing or retail service purposes, provided that the same utility serves all of its meters;

5. Uses not more than 25% of the contiguous land owned or controlled by the agricultural business for purposes of the renewable energy generating facility; and

6. Provides the electric utility with a certification, attested under oath, as to the amount of land being used for renewable generation.

"System peak" for an electric cooperative, means the highest peak, based on the noncoincident peak of the electric cooperative or the coincident peak of all of the electric cooperative's customers of the past three years listed in Part O, Line 20 of Form 7 (Financial And Operating Report - Electric Distribution) filed with the U.S. Department of Agriculture's Rural Utilities Service (RUS), or an equivalent form if a cooperative is not an RUS borrower, less any portion of the cooperative's total load that is served by a competitive service provider or by a market-based rate.

"Third-party partial requirements power purchase agreement" or "third-party PPA" means, for an electric cooperative, an agreement entered into pursuant to § 56-594.01 K of the Code of Virginia between a customer engaging in net energy metering and a registered PPA provider pursuant to 20VAC5-315-77.

"Time-of-use customer" means an agricultural net metering customer or net metering customer receiving retail electricity supply service under a demand charge-based time-of-use tariff.

"Time-of-use period" means an interval of time over which the energy (kilowatt-hour) rate charged to a time-of-use customer does not change.

"Time-of-use tier" or "tier" means all time-of-use periods given the same name (e.g., on-peak, off-peak, critical peak, etc.) for the purpose of time-differentiating energy (kilowatt-hour) based charges. The rates associated with a particular tier may vary by day and by season.

"Triggering project" means a project application in the interconnection queue at a given substation or feeder that requires a qualifying upgrade to successfully interconnect the project to the electric distribution system.

20VAC5-315-100. Distribution cost sharing program.

A. Purpose and applicability.

1. The purpose of this section is to implement the distribution cost sharing program pursuant to the provisions of § 56-596.6 of the Code of Virginia for a generating facility with an alternating current nameplate capacity greater than 250 kilowatts and less than or equal to three megawatts that seeks to interconnect to a Phase I or Phase II Utility's distribution system and participate in net energy metering pursuant to § 56-594 of the Code of Virginia.

2. This section applies to Phase I and Phase II Utilities and to all triggering projects and sharing projects, as defined in 20VAC5-315-20, interconnecting pursuant to this section.

3. Each Phase I and Phase II Utility shall file on or before December 1, 2026, tariffs and forms, and a Distribution Cost Sharing Agreement consistent with this section, subject to commission approval. These documents should:

a. Conform to the parameters of this section.

b. Describe any utility-specific procedures and system configurations.

c. Include applicable administrative and processing fees as permitted by subsection G of this section.

B. Identification of qualifying upgrades and documentation.

1. When the utility determines through a system impact study that a qualifying upgrade is required to interconnect a triggering project, the utility shall:

a. Identify any specific upgrade, including location and function.

b. Determine an estimate of the cost of such qualifying upgrade, broken out by major cost categories (materials, internal labor, and other direct costs).

c. Determine and document the net increase in hosting capacity, expressed in kilowatts or megawatts, attributable to the qualifying upgrade.

2. The utility shall provide the applicant of the triggering project, and any subsequently queued applicants with projects on the affected circuit, with a study report that:

a. Identifies each qualifying upgrade and any non-qualifying upgrades.

b. Provides the estimated cost of each qualifying upgrade and the net increase in hosting capacity.

c. States the cost-sharing window opening date and estimated closing date, subject to subsection E of this section.

C. Determination of qualifying upgrade costs.

1. Costs of qualifying upgrades shall be determined by the utility using its Unit Cost Guide.

2. For each qualifying upgrade, the utility shall document:

a. The quantities of standard components and work items and the associated unit costs drawn from the Unit Cost Guide.

b. Any site-specific or non-standard cost elements and the basis for such costs.

c. The resulting total qualifying upgrade cost used for allocation under subsection D of this section.

3. The Unit Cost Guide shall be updated on an annual basis. Utilities shall not be required to seek project-specific commission approval of qualifying upgrade costs when such costs are calculated in accordance with the Unit Cost Guide, applicable standards, and good utility practice.

D. Cost allocation formula and thresholds.

1. Each utility shall apply a pro-rata cost allocation methodology under which the approved cost of qualifying upgrades is allocated among participating projects based on each project's alternating current nameplate capacity relative to the total alternating current nameplate capacity of all participating projects benefiting from the qualifying upgrade.

2. Unless otherwise approved by the commission, the allocation shall be calculated as follows:

A project's allocated share of qualifying upgrade cost is equal to the amount of the project alternating current nameplate in kilowatts divided by the sum of alternating current nameplate in kilowatts for all participating projects, then that amount multiplied by the approved qualifying upgrade cost.

3. The triggering project shall initially pay 100% of the estimated qualifying upgrade costs prior to construction, with subsequent sharing projects reimbursing the triggering project (and any prior sharing projects) for their proportional shares as payments are received.

4. The same cost allocation methodology shall apply to the reconciliation of estimated and actual qualifying upgrade costs at the conclusion of construction, with refunds or additional billings as provided in subsection F of this section.

5. The distribution cost sharing program shall apply only where:

a. The total estimated cost of a qualifying upgrade equals or exceeds $100,000.

b. The net increase in hosting capacity attributable to the qualifying upgrade is at least 500 kilowatts, measured at the relevant circuit node or point of common coupling.

E. Cost-sharing window and participation.

1. For each qualifying upgrade, the utility shall establish a cost-sharing window during which sharing projects may be allocated costs and triggering and sharing projects may receive refunds.

2. The default cost-sharing window shall be five years from the date the qualifying upgrade is placed in service.

3. Cost sharing shall terminate upon the earlier of:

a. The end of the cost-sharing window.

b. The point at which the net increase in hosting capacity created by the qualifying upgrade is fully utilized.

c. The point at which the remaining net cost of the qualifying upgrade to participating projects falls below the $100,000 threshold.

4. A triggering project may elect to opt out of the distribution cost sharing program by paying in full the approved cost of any associated qualifying upgrade, in which case such project shall not be treated as a sharing project and shall not be eligible to receive funds under this section.

F. Payments, reconciliation, and refunds.

1. Payment obligations.

a. Prior to the construction of qualifying upgrades, the triggering project shall pay the utility the estimated costs of all required interconnection upgrades, including qualifying and nonqualifying upgrades.

b. Each sharing project shall pay its allocated share of qualifying upgrade costs, plus its own nonqualifying upgrade costs, prior to construction of any upgrades necessary for its interconnection.

2. Reconciliation of estimated and actual costs.

a. Upon completion of the qualifying upgrade, the utility shall determine actual costs and recalculate each project's share under subsection D of this section.

b. The utility shall issue a final bill or refund to each participating project reflecting the difference between the amounts previously paid and the project's final allocated share, net of any applicable administrative or processing fees approved under subsection G of this section.

3. Refunds during cost-sharing window.

a. Refunds based on new sharing projects.

(1) When a new sharing project enters the program within the cost-sharing window and pays its allocated share of qualifying upgrade costs, the utility shall recalculate cost responsibility for all participating projects using the methodology in subsection D of this section.

(2) The utility shall then issue refunds or additional bills, as applicable, so that each participating project's net payments reflect its updated allocated share, net of applicable administrative and processing fees.

(3) These refunds and additional bills shall be administered automatically by the utility and shall not require a petition to the commission.

b. Final billing process.

(1) After all participating projects associated with a qualifying upgrade have been approved for operation, and actual qualifying upgrade costs are known, the utility shall perform a final reconciliation of costs and allocations under subsection E of this section.

(2) The utility shall issue any final refunds or additional bills so that each participating project's total payments equal its final allocated share of the actual qualifying upgrade costs, net of applicable administrative and processing fees.

c. Refunds during the cost-sharing window shall occur in the two circumstances described in subdivisions 3 a and 3 b of this subsection.

d. Process and timing.

(1) For refunds and additional bills issued under subdivisions 3 a and 3 b of this subsection, the utility shall perform the recalculation and issue any resulting refund or additional bill within 60 days of (i) receipt of payment from the new sharing project in the case of subdivision 3 a of this subsection or (ii) completion of the final reconciliation after all participating projects have been approved for operation in the case of subdivision 3 b of this subsection.

(2) Refunds may be issued either as direct payments or as bill credits applied to future interconnection-related charges under this program, at the election of the project owner, as provided in the utility's tariff.

G. Administrative and processing fees.

1. Each utility shall include in its compliance filing reasonable administrative and processing fees to recover incremental costs of designing, implementing, and operating systems necessary to track qualifying upgrades, cost allocations, payments, and refunds and to avoid cost shifting to nonparticipating customers.

2. Administrative and processing fees may include:

a. A one-time application or program enrollment fee for projects electing to participate in the distribution cost sharing program.

b. A per-allocation processing fee assessed on participating projects each time the costs of a qualifying upgrade are reallocated due to the addition of a new sharing project or final reconciliation.

c. A processing fee for each refund administered as part of a cost-sharing recalculation or nonoperational refund.

3. Administrative and processing fees shall be subject to commission review and approval.

H. Jurisdictional and nonjurisdictional cost allocation.

1. The costs attributed to jurisdictional triggering projects shall be recovered only from jurisdictional sharing projects, and costs attributed to nonjurisdictional triggering projects shall be recovered only from nonjurisdictional sharing projects, consistent with § 56-596.6 of the Code of Virginia.

2. Each utility shall identify and document within the Distribution Cost Sharing Agreement whether a project is jurisdictional or nonjurisdictional and shall maintain records sufficient to demonstrate compliance with this subsection.

I. Dispute resolution.

1. In the event of a dispute arising out of the program, either party (project owners or utility) shall provide the other parties with a written notice of dispute. The notice shall describe in detail the nature of the dispute, which may include: (i) the designation of or cost of a qualifying upgrade, (ii) the calculation of net hosting capacity, (iii) cost allocations under subsection D of this section, and (iv) eligibility for or amount of a refund under subsection F of this section. The parties shall make a good faith effort to resolve the dispute informally within 10 business days.

2. If the dispute has not been resolved within 10 business days after receipt of the notice, either party may seek resolution assistance from the Division of Public Utility Regulation where the matter will be handled as an informal complaint.

Alternately, the parties may, upon mutual agreement, seek resolution through the assistance of a dispute resolution service. The dispute resolution service will assist the parties in either resolving the dispute or selecting an appropriate dispute resolution venue (e.g., mediation, settlement judge, early neutral evaluation, or technical expert) to assist the parties in resolving the dispute. Each party shall conduct all negotiations in good faith and shall share equally in any costs paid to neutral third parties.

3. If the dispute remains unresolved, either party may petition the commission to handle the dispute as a formal complaint or may exercise whatever rights and remedies the party may have in equity or law.

J. Reporting and transparency. Each utility shall submit to the Division of Public Utility Regulation, on a biannual basis, a report listing all executed Distribution Cost Sharing Agreements and associated qualifying upgrades during the reporting period, including:

1. Circuit or node identifier.

2. Description of all qualifying upgrades.

3. Initial estimated and actual costs.

4. Net increase in hosting capacity.

5. Identity and alternating current nameplate capacity of triggering and sharing projects.

6. Cost allocations.

7. Payments received.

8. Refunds issued.

9. Administrative and processing fees collected.