Data-center fixtures that are taxed under Virginia’s property-tax laws must be assessed using the cost approach, which values them based on reproduction or replacement cost minus physical, functional, and economic depreciation. This creates a property-tax assessment requirement for covered fixtures, including power, cooling, HVAC, water, monitoring, and transmission equipment; computer equipment and peripherals, external surveillance and security equipment, and fire and burglar alarm systems are excluded.

Data-center fixtures taxed under the chapter must be assessed using the cost approach—reproduction or replacement cost minus physical, functional, and economic depreciation—rather than an income-based valuation. This applies only to qualifying fixtures, excluding computer equipment and peripherals, external surveillance and security equipment, and fire and burglar alarm systems. Cost-based assessment requirement

The measure creates a separate local personal-property-tax classification for computer equipment and peripherals used in data centers and requires that equipment to be valued using a percentage of original cost or another method reasonably expected to determine fair market value. This can affect operating tax assessments; it does not itself set a tax rate or require a locality to levy the tax. Data-center equipment valuation

Computer equipment and peripherals used in a data center receive a separate valuation category. They may be valued using a percentage of original cost or another method reasonably expected to determine actual fair market value. The data-center equipment valuation rule

Localities may tax the separately classified data-center property at a different rate from other tangible personal property; the rate may not exceed the rate for the general tangible-personal-property class. Localities may levy different rates

Before approving a rezoning, special exception, or special use permit for a new high energy use facility requiring 100 megawatts or more, the locality must require the applicant to submit a site assessment of the facility’s sound profile on residences and schools within 500 feet of the property boundary. The assessment must be completed as practicable within the applicable statutory timeline. The 100-megawatt threshold and required sound assessment

A locality may require the applicant’s site assessment to examine impacts on ground and surface water, agricultural resources, parks, registered historic sites, and forestland on the facility site or immediately contiguous land. The additional subjects a locality may require the assessment to examine

Before approval of a rezoning, special exception, or special use permit for a new high energy use facility, the serving retail electric utility must submit a form, to the extent known and practicable and within the applicable statutory timeline, identifying the new or existing substations that will serve the facility and the anticipated transmission voltage. The utility information required before approval

The locality must use the submitted site assessments to evaluate consistency with its comprehensive plan and compliance with local noise ordinances, zoning provisions, and other applicable laws and regulations, creating an additional review requirement before approval. How the locality must use the site assessments

An existing or approved facility may expand or be modified without being subject to this section’s site-assessment requirements when the expansion does not exceed the stated additional 100-megawatt threshold. This exemption applies to expansions or modifications of already existing or approved facilities.

No direct operator restriction identified; Chapter 591 assigns duties to the Department of Energy.

Facilitates connections with potential public and private heat users and includes the data center industry in the work group.

Before a locality may approve a rezoning application, special exception, or special use permit for a new high energy use facility requiring 100 megawatts or more, the applicant must submit a site assessment of the facility’s sound profile as it affects residential units and schools within 500 feet of the property boundary.

A locality may require the site assessment for a new high energy use facility to evaluate effects on ground and surface water, agricultural resources, parks, registered historic sites, and forestland on the site or immediately contiguous land.

Before approval of the required zoning application for a new high energy use facility, the serving electric utility must submit a form identifying the new or existing substations that will serve the facility and the anticipated transmission voltage, to the extent known and practicable.

Facilities that are not reasonably anticipated to require at least 100 megawatts of electricity are not covered by the high energy use facility requirements in this section. The definition sets the threshold at 100 megawatts or more.

An already existing or approved facility may be expanded or modified without triggering this section’s site-assessment requirements when the expansion does not add 100 megawatts or more of electrical power. The exemption applies to expansions or modifications not exceeding the stated additional power limit.

Required site assessments must be performed only to the extent practicable and within the statutory review timeline, limiting the assessment burden and potential permitting delay. Assessments must be completed to the extent practicable and within the applicable timeline.

The mandatory sound-profile assessment is limited to residential units and schools located within 500 feet of the facility boundary; reviews of water, agricultural, park, historic-site, and forestland impacts are discretionary for the locality. The required sound review covers residences and schools within 500 feet.

Data-center fixtures taxed as real property must be assessed using the cost approach: reproduction or replacement cost less physical, functional, and economic depreciation. This applies only to fixtures taxed under the real-property chapter; fixtures taxed this way are excluded from tangible personal property. The cost-approach requirement and its scope

Data-center fixtures taxed under the real-property tax chapter must be valued using the cost approach: the cost to construct a reproduction or suitable replacement, minus physical, functional, and economic depreciation. This replaces valuation based on income generated by the fixtures, but does not guarantee a lower assessment. The rule excludes computer equipment and peripherals, external surveillance and security equipment, and fire and burglar alarm systems from the definition of fixtures. Fixtures shall be assessed using the cost approach.

Computer equipment and peripherals used in a data center receive a separate valuation classification. They may be valued using a percentage of original cost or another method reasonably expected to determine actual fair market value, rather than being subject to the general business-property valuation category. See subdivision A 17

Computer equipment and peripherals used in a data center are established as a separate class for local taxation. A county, city, or town may tax this class at a different rate from other tangible personal property, but the rate and assessment rate may not exceed those applicable to the general tangible-personal-property class; if property qualifies for multiple classifications, the lowest applicable tax rate applies. See the data-center classification and rate limits

Before approving a rezoning, special exception, or special use permit for a new high energy use facility requiring at least 100 megawatts of utility power, the locality must require the applicant to submit a site assessment examining the facility’s sound profile on residential units and schools within 500 feet of the property boundary, to the extent practicable and within the applicable statutory timeline. site assessment

A locality may require the site assessment for a new 100-megawatt-or-more facility to examine effects on ground and surface water, agricultural resources, parks, registered historic sites, and forestland on the site or immediately contiguous land, creating additional site-review requirements when imposed. effect of the proposed facility

Before approving a rezoning, special exception, or special use permit for a new high energy use facility, the locality must require the serving electric utility to submit a form, to the extent known and practicable and within the applicable statutory timeline, identifying new or existing substations that will serve the facility and the anticipated transmission voltage. submit to the locality a form

Expansions or modifications of an already existing or approved facility are exempt from the new site-assessment requirements when the additional electrical capacity does not exceed 100 megawatts, subject to the site having an existing legislative or administrative approval.

For overhead transmission lines of 500 kilovolts or more constructed by Dominion Energy Virginia, the State Corporation Commission must prioritize approving corridors or routes whose center is more than 150 feet from any dwelling house, public or private school building, day care, or place of worship, unless no other practicable alternative exists. This can support construction of major electric-transmission infrastructure for electricity-intensive facilities, including data centers.

A cooperative substation-construction agreement is available only for a member receiving regulated electric service whose demand was at least 20 megawatts during the most recent calendar year and whose project requires an interconnection with a transmission system of 230 kilovolts or more.

The member must construct the substation at its sole expense, for dedicated service only to its facilities, and in compliance with applicable laws, regulations, reliability standards, and the cooperative’s specifications.

After substantial completion, the member must provide written notice; the cooperative then has up to 60 days to inspect the substation and an additional 30 days after inspection to issue final construction change orders.

Upon final completion, the member must transfer ownership and control of the substation to the cooperative by donation or mutually agreed consideration.

After transfer, the cooperative will operate and maintain the substation at the member’s sole expense under the cooperative’s applicable rates, terms, and conditions.

The State Corporation Commission must exclude the substation’s acquisition, operation, and maintenance costs from the cooperative’s general and base rates, so those costs cannot be recovered from any ratepayer other than the member that entered the agreement.

If the cooperative does not negotiate or propose a draft agreement within 120 days after the member’s written request, the member may petition the Commission to order negotiations and a draft agreement; the member must pay the Commission’s fee for adjudicating the petition.

An eligible large-load facility, including a data center that meets the thresholds, may arrange with an electric cooperative to construct a dedicated substation. Eligibility requires regulated electric service, at least 20 megawatts of demand during the most recent calendar year, and a required interconnection with a transmission system of 230 kilovolts or more. The facility must pay the substation's construction cost and comply with applicable laws, regulations, reliability standards, and the cooperative's specifications. may enter into an agreement to construct a substation

The substation-construction agreement must be filed with the State Corporation Commission for informational purposes, and the Commission must treat it as confidential if requested by the parties. filed jointly by the member and cooperative for informational purposes

The law establishes construction-completion deadlines: after the facility notifies the cooperative of substantial completion, the cooperative must inspect within 60 days and issue any final construction change orders within 30 days after the inspection. Within 60 days after receiving such notice

After final completion, the facility must transfer ownership and control of the substation to the cooperative by donation or mutually agreed consideration. The cooperative then operates and maintains it for the facility at the facility's sole expense under the cooperative's applicable rates, terms, and conditions. the member shall transfer ownership and control to the cooperative

The Commission must exclude the substation's acquisition, operation, and maintenance costs from the cooperative's general and base rates and prohibit recovery of those costs from ratepayers other than the facility that entered the agreement. no costs associated with such substation are recovered from any ratepayer other than the member

Agreements and acquisitions made under this section are exempt from the specified provisions of Virginia's electric-utility and public-service-company chapters, potentially reducing regulatory requirements for the substation arrangement. No provision of Chapter 5

The facility and cooperative must negotiate in good faith. If the cooperative does not negotiate or propose a draft agreement within 120 days after a written request, the facility may petition the Commission to order negotiations and a draft agreement; the Commission must hear the petition, if necessary, within three months and issue an order within six months. fails to negotiate or fails to propose a draft agreement within 120 days

The facility and cooperative may use the State Corporation Commission's informal and formal dispute-resolution processes for disputes arising during negotiations, construction, or transfer of the substation. recourse through the informal and formal dispute resolution processes

Requires utilities’ integrated resource plans to assess energy-storage resources using modeling that accounts for economic charging and discharging times and different economic scenarios.

Requires utilities to evaluate investments in energy-storage resources as part of their integrated resource planning.

Requires utilities to develop long-term plans for integrating new energy-storage resources into existing generation and distribution assets to support grid transformation.

Requires long-term electric distribution-grid planning to assess grid-enhancing technologies and advanced conductors for reliability and cybersecurity and physical security. A utility that excludes those technologies must explain why.

Directs the State Corporation Commission to initiate, by March 1, 2027, an investigation of electric-load forecasting practices by Dominion Energy, Appalachian Power Company, and electric distribution cooperatives.

High-energy-demand-customer requirements apply to retail electric customers with a contracted or measured demand of at least 25 megawatts and an anticipated or measured average annual load factor of at least 75 percent, excluding contracted defense facilities. Definition of “high energy demand customer”

Phase I and Phase II utilities must establish voluntary demand-flexibility programs for qualifying high-energy-demand customers. The programs must include Commission-approved annual demand-flexibility standards that utilities, working with those customers, must make best, reasonable efforts to meet or exceed. Utilities must petition for approval by January 15, 2027, and the Commission must issue final orders by November 30, 2027. file a petition with the Commission

A participating high-energy-demand customer may need to reduce or shift its own electricity use or secure measured and verified load reductions from other retail customers, including through capacity-reduction credits. Any participation incentives are contingent on verified reductions in peak demand or verified reductions secured from other customers. capacity reduction credits

Carbon-emitting generating resources cannot be used to participate in a demand-flexibility program or to meet its demand-flexibility standards. carbon-emitting generating resources will be ineligible

A cooperative serving one or more qualifying high-energy-demand customers must establish a voluntary demand-flexibility program by January 1, 2029. The program must include a Commission-approved demand-flexibility standard, and the cooperative must make best, reasonable efforts to meet it; the program must also prohibit customers from meeting the standard with carbon-emitting generation. By January 1, 2029

Data centers that qualify as high energy demand customers—generally those with at least 25 megawatts of contracted or measured demand and an average annual load factor of at least 75 percent—may participate in voluntary demand flexibility programs rather than being required to participate. The programs are intended to improve grid reliability and maximize system savings. The programs apply to high energy demand customers.

A qualifying data center may meet demand flexibility requirements without directly reducing its own electricity use by funding, supporting, or purchasing capacity reduction credits from other retail electric customers. Any reductions must be measurable and verifiable, and the Commission must establish the measurement and verification method. customers may be eligible to participate without directly curtailing their own electricity use.

If a demand flexibility program offers incentives, the Commission or cooperative may include procedures for accelerated interconnection for participating high energy demand customers. The acceleration cannot sacrifice electric-grid reliability, and the incentives are contingent on measured and verified demand or load reductions. incentives may also include open and transparent procedures for accelerated interconnection.

The State Corporation Commission must analyze whether each covered utility could improve grid utilization through non-wires alternatives, including power-quality monitoring equipment at the point of interconnection for customers with measured or contracted demand of 25 megawatts or greater. This can apply to very large data centers, but the act requires analysis rather than installation.

Requires Dominion Energy and Appalachian Power, as Phase I or Phase II utilities, to petition the State Corporation Commission by October 15, 2026, for electric-grid utilization metrics and to assess current distribution and transmission performance against optimal use of existing grid assets.

Requires proposed metrics to measure distribution-capacity utilization, delivered load versus potential deliverable load, distribution losses, constrained circuits, and system performance during peaks—information that can identify available capacity for additional large loads.

Directs the Commission to determine how approved metrics will apply at feeder and substation levels and how they will be reported in future integrated resource plans, including seasonal assessments where appropriate.

Requires the Commission, when approving metrics, to establish timelines for each covered utility to increase grid utilization and explain how the metrics may inform approval of future utility capital-investment cost recovery.

Requires the Commission’s annual report to analyze whether each covered utility can increase grid utilization through non-wires alternatives, including energy storage, customer-owned or customer-financed capacity, utility-owned or contracted distributed generation, virtual power plants, flexible transmission equipment, synchronous condensers, and other listed resources.

Requires analysis of power-quality monitoring equipment at the interconnection point for customers with measured or contracted demand of 25 megawatts or greater, directly covering qualifying large-load customers such as major data centers.

Allows the Commission to request information from each covered utility needed to evaluate non-wires alternatives and other methods of improving grid utilization, supporting review of infrastructure options for large-load interconnections.

High energy demand customers—retail customers with contracted or measured demand of at least 25 megawatts and an average annual load factor of at least 75 percent—must work with their utility under a voluntary demand flexibility program and make best, reasonable efforts to meet or exceed an annual demand flexibility standard. The programs apply to Phase I and Phase II utilities, with utility petitions due by January 15, 2027, and Commission decisions due by November 30, 2027. The definition of “high energy demand customer” and the annual standard requirement

A high energy demand customer may not use carbon-emitting generating resources to satisfy demand flexibility requirements. Carbon-emitting generating resources will be ineligible

Participation incentives are contingent on measuring and verifying the customer's peak-demand reductions or load reductions obtained from other retail customers, creating measurement and verification requirements for customers seeking those incentives. Any such incentives shall be contingent upon the measurement and verification

Each cooperative serving at least one high energy demand customer must establish a voluntary demand flexibility program by January 1, 2029, and participating high energy demand customers must make best, reasonable efforts to meet the cooperative's Commission-approved demand flexibility standard. By January 1, 2029 and make best, reasonable efforts to meet

Phase I and Phase II utilities must establish voluntary demand-flexibility programs for qualifying high energy demand customers—customers with at least 25 MW of contracted or measured demand and an average annual load factor of at least 75 percent, subject to other statutory exclusions. The programs are intended to improve grid reliability and maximize system savings without making participation mandatory. (voluntary demand flexibility program)

A qualifying high energy demand customer may satisfy demand-flexibility requirements without directly reducing its own electricity use by funding, supporting, or purchasing verified capacity-reduction credits from other retail customers. (without directly curtailing their own electricity use)

Approved programs may include open and transparent incentives for accelerated interconnection to electric service for participating high energy demand customers, provided the accelerated connection does not compromise electric-grid reliability. (accelerated interconnection to service)

Utilities must consider multiple ways for high energy demand customers to manage or offset grid demand, including geographic or time shifting, dynamic voltage and frequency scaling, energy storage, and verified reductions obtained through other customers or third-party providers. (all forms of demand flexibility)

Cooperatives serving one or more qualifying high energy demand customers must establish voluntary demand-flexibility programs by January 1, 2029, and may allow customers to participate through purchased capacity-reduction credits rather than directly curtailing their own use. (each cooperative that serves one or more high energy demand customers shall establish)

Effective January 1, 2027, a water user already required to register withdrawal data that provides water offsite must separately report the monthly potable and reclaimed-water volumes supplied to a data center with a Department of Environmental Quality air permit. If monthly data is unavailable, quarterly reporting is allowed. This adds reporting and compliance requirements for water suppliers serving qualifying data centers; it does not impose a construction ban or direct operating limit on data centers. (reporting requirements for water supplied to data centers)

Covered offsite water suppliers must report separate monthly potable and reclaimed-water volumes for a data center with a DEQ air permit; quarterly reporting is permitted where monthly data is not available. The act is effective January 1, 2027.