Bill Text: VA SB1769 | 2019 | Regular Session | Chaptered
Bill Title: Electric utilities; net energy metering.
Spectrum: Partisan Bill (Republican 1-0)
Status: (Passed) 2019-03-21 - Governor: Acts of Assembly Chapter text (CHAP0763) [SB1769 Detail]
Download: Virginia-2019-SB1769-Chaptered.html
Be it enacted by the General Assembly of Virginia:
1. That §§56-585.1:3, 56-585.3, and 56-594 of the Code of Virginia are amended and reenacted and that the Code of Virginia is amended by adding sections numbered 56-585.4 and 56-594.01 as follows:
§56-585.1:3. Pilot programs for community solar development.
A. As used in this section:
"Eligible generation facility" means an electrical generation facility that:
1. Exclusively uses energy derived from sunlight;
2. Is placed in service on or after July 1, 2017;
3. Is not constructed by an investor-owned utility and either (i) is acquired by an investor-owned utility through an asset purchase agreement or (ii) is subject to a power purchase agreement under which an investor-owned utility purchases the facility's output from a third party; and
4. Has a generating capacity of:
a. Not more than two megawatts; or
b. More than two megawatts if not more than two megawatts of the output from the electrical generation facility is selected in an investor-owned utility's RFP for dedication to its pilot program.
"Generating capacity" means an electrical generation facility's nameplate rated capacity measured in direct current megawatts.
"Investor-owned utility" means an electric utility that is a Phase I Utility or a Phase II Utility.
"Participating generating facility" means an eligible generation facility that is selected by an investor-owned utility through its RFP for inclusion in its pilot program.
"Participating third party" means, for investor-owned utilities, a Virginia nonresidential-class customer, an affiliate, a solar development entity, or a nonjurisdictional customer that takes on the obligation, as part of a variable-output contract, of pilot program costs not recovered through the voluntary companion rate schedule as specified in subdivision B 8.
"Participating utility" means (i) each investor-owned utility and (ii) any utility consumer services cooperative that elects to conduct a pilot program under subsection C.
"Phase I Utility" means an investor-owned incumbent electric utility that was, as of July 1, 1999, not bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002.
"Phase II Utility" means an investor-owned incumbent electric utility that was, as of July 1, 1999, bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002.
"Pilot program" means a community solar pilot program conducted by a participating utility pursuant to this section following approval by the Commission, under which the participating utility sells electric power to subscribing customers under a voluntary companion rate schedule and the participating utility generates or purchases electric power from participating generation facilities selected by the participating utility.
"Pilot program costs" means all of a participating utility's identified, projected, and actual costs of its pilot program, including costs for (i) purchased power; (ii) renewable and other environmental attributes; (iii) transmission and distribution services; (iv) generating capacity and energy balancing; (v) RFP process costs; (vi) administrative and marketing charges; (vii) capital costs and operations and maintenance expenses related to building, owning, and operating eligible generating facilities; and (viii) a reasonable margin, which margin shall be the weighted average cost of capital.
"Pilot program period" means the three-year period ending three years following the date the first subscription is entered into by a customer.
"RFP" means the request for proposal process conducted by an investor-owned utility.
"Small eligible generation facility" means an eligible generation facility with a generating capacity of less than 0.5 megawatt.
"Solar development entity" means a business entity organized primarily for the purpose of proposing, developing, constructing, purchasing, or selling at wholesale all or part of the output of an eligible generation facility. A solar development entity may be organized in any form and may be a special purpose entity.
"Utility aggregation cooperative" has the same meaning ascribed to "cooperative" in §56-231.38.
"Utility consumer services cooperative" has the same meaning ascribed to "cooperative" in §56-231.15.
"Voluntary companion rate schedule" means a rate schedule approved by the Commission upon application by a participating utility that provides for the recovery of the pilot program costs by the participating utility.
B. Notwithstanding the provisions of subsection B of §56-234 and §§56-249.6 and 56-585.1, each investor-owned utility shall conduct a pilot program for retail customers as follows:
1. Each investor-owned utility shall design its own pilot program and within six months of receiving Commission approval shall make subscriptions for participation in its pilot program available to its retail customers on a voluntary basis.
2. An investor-owned utility shall select eligible generating facilities for dedication to its pilot program through an RFP process, under which process:
a. Each investor-owned utility shall have issued one or more public RFPs for eligible generating facilities and the purchase of all energy output and associated renewable energy certificates and other environmental attributes.
b. Each RFP shall:
(1) State the price and non-price criteria used by the investor-owned utility in selecting proposals for dedication to its pilot program; and
(2) Require as a criterion for selection that eligible generating facilities with a combined generating capacity of not less than two megawatts, and any eligible generating facility with a generating capacity of more than two megawatts, be first placed in service on or after July 1, 2017.
c. Each investor-owned utility is authorized to select, under an asset purchase or power purchase agreement, small eligible generating facilities for dedication to its pilot program without regard to whether price criteria are satisfied by their selection if the selection of the small eligible generating facilities materially advances non-price criteria, including a criterion favoring geographic distribution of eligible generating facilities, provided that the generating capacity of small eligible generating facilities does not exceed 25 percent of the utility's pilot program's minimum generating capacity specified in subdivision 3.
d. An investor-owned utility shall not select through its RFP an electrical generation facility with a generating capacity of more than two megawatts for its pilot program unless (i) the costs can be appropriately documented for the portion of the facility's output, which portion shall not exceed two megawatts, that is dedicated to the pilot program and (ii) for a Phase II Utility only, the portion of the facility's generating capacity selected pursuant to this subdivision does not exceed 50 percent of the investor-owned utility's pilot program's minimum generating capacity specified in subdivision 3. The portion of the facility's generating capacity that exceeds the portion of the facility's generating capacity that is selected pursuant to this subdivision shall not be applied in determining whether the pilot program satisfies requirements of subdivision 3 regarding a pilot program's minimum generating capacity.
e. In selecting eligible generating facilities for dedication to its pilot program, an investor-owned utility shall give due consideration to relative costs, economic development benefits, and geographic diversity of eligible generating facilities.
f. The investor-owned utility's application to the Commission shall include a description of the application of the price and non-price criteria in the investor-owned utility's selection of participating generating facilities from among the proposals submitted in response to the RFP.
3. The amount of generating capacity of the eligible generating facilities in an investor-owned utility's pilot program shall not be less than (i) 0.5 megawatt if the pilot program is conducted by a Phase I Utility or (ii) 10 megawatts if the pilot program is conducted by a Phase II Utility.
4. The amount of generating capacity of the eligible generating facilities in an investor-owned utility's pilot program shall not exceed (i) 10 megawatts if the pilot program is conducted by a Phase I Utility or (ii) 40 megawatts if the pilot program is conducted by a Phase II Utility.
5. An investor-owned utility shall have the option of increasing the amount of generating capacity of the eligible generating facilities in its pilot program above the amount most recently approved by the Commission, in such increments as the investor-owned utility elects, as follows:
a. Any such increase shall not result in an amount of generating capacity that exceeds the cap specified for the investor-owned utility's pilot program under subdivision 4;
b. No such increase shall be authorized until such time that 90 percent of the amount of generating capacity of the eligible generating facilities then approved for its pilot program has been subscribed by customers through the investor-owned utility's voluntary companion rate schedule;
c. An investor-owned utility may seek any number of increases in the amount of generating capacity of the eligible generating facilities in its pilot program, subject to the conditions in subdivisions a and b; and
d. The investor-owned utility shall select eligible generating facilities for any increase in the generating capacity of its pilot program through an RFP process that complies with the requirements of subdivision 2.
6. Each pilot program shall expire at the end of its pilot
program period, unless renewed or made permanent by appropriate legislation
as provided in subsection G.
7. The renewable energy certificates and other environmental attributes associated with the voluntary companion rate schedule shall be retired by the investor-owned utility on the subscribing customer's behalf.
8. An investor-owned utility shall recover all its pilot program costs primarily through its voluntary companion rate schedule. However, pilot program costs that are not recovered through the voluntary companion rate schedule shall be recoverable from a participating third party and not from the investor-owned utility's Virginia jurisdictional customers. To the extent participating third parties are obligated for pilot program costs not recovered through the voluntary companion rate schedule, variable-output contracts between participating third parties other than affiliates and investor-owned utilities shall be negotiated at arm's length and shall not be reviewable by the Commission and shall require no further Commission approvals pursuant to Chapter 4 (§56-76 et seq.) or other applicable law.
9. At the conclusion of the pilot program period, to the extent that the pilot program is not made permanent or extended, each participating generating facility shall cease to be part of the pilot program and shall return to operation under the variable-output contract with a participating third party.
10. Any fixed generation costs and fixed purchased power costs shall remain fixed for subscribing customers throughout the duration of the subscribing customers' continuous and uninterrupted participation in the voluntary companion rate schedule. A subscribing customer's participation in the voluntary companion rate schedule shall be deemed to be continuous and uninterrupted notwithstanding a change in the location where the customer receives service if the new location continues to be within the investor-owned utility's service territory and the customer provides the investor-owned utility with notice of the change prior to or within 90 days following the change. Investor-owned utilities are authorized to decrease the generation or purchased power rate, or both, at any time to reflect cost reductions, if any, subject to Commission review. If, pursuant to subdivision 9, the pilot program is not made permanent or continued, the subscribing customers' subscriptions to the voluntary companion rate schedule shall survive the termination of the pilot program.
11. A subscribing customer's usage that exceeds the amount subscribed for under the voluntary companion rate schedule shall be billed under the customer's applicable standard rate.
12. An investor-owned utility shall not require a subscribing customer to enter an agreement or subscription for participation in a pilot program of more than 12 months' duration unless the subscribing customer's subscription exceeds 100 kW, or its equivalent in kWh, at the time the customer initially enters into the agreement or subscription.
13. As part of an arrangement with a solar development entity, a utility may enter into an agreement that provides for risk sharing and collaboration in marketing a utility's pilot program if the solar development entity is a participating third party.
14. An investor-owned utility shall have the ability to close its pilot program to new subscribers according to the terms of the voluntary companion rate schedule upon notice to the Commission. This option shall be exercisable once per year, upon the anniversary date of the Commission's order approving the voluntary companion rate schedule.
C. Notwithstanding the provisions of subsection B of §56-234 and §§56-249.6 and 56-585.1, upon application of a utility consumer services cooperative the Commission shall review a proposal submitted by the cooperative for a voluntary companion rate schedule. If the Commission finds that the proposal is reasonable and prudent, it shall approve the voluntary companion rate schedule for the cooperative to conduct a pilot program pursuant to this section. No utility consumer services cooperative shall be required to conduct a pilot program pursuant to this section. In making an application to the Commission pursuant to this subsection, a utility consumer services cooperative shall have flexibility to design its voluntary companion rate schedule in a manner that, notwithstanding anything to the contrary in this section, provides the cooperative the ability to:
1. Construct or purchase its generating facilities, or dedicate a portion of its existing power supply portfolio, for its community solar pilot program along with one or more other utility consumer services cooperatives, one or both Phase I or Phase II Utilities, or a utility aggregation cooperative, through requests for proposal or through a contract with a third party or a utility aggregation cooperative;
2. If constructing or purchasing its generating facilities, or dedicating a portion of its existing power supply portfolio, for its pilot program through a utility aggregation cooperative, include generating facilities that may be already in service or may be first placed into service at any time;
3. Utilize generating facilities of any generating capacity for its pilot program;
4. Physically locate the generating facilities used for the pilot program inside or outside of its certificated service territory;
5. Design its voluntary companion rate schedule in coordination with one or more utility consumer services cooperatives, such that participating subscribers from both cooperatives subscribe to an identical rate schedule;
6. Permanently end its pilot program for all subscribers according to the terms of the voluntary companion rate schedule; and
7. Recover pilot program costs that are not recovered through the voluntary companion rate schedule by including unrecovered purchased power expense in the cooperative's cost of purchased power and through a regulatory asset for unrecovered costs that are not purchased power expense, subject to the oversight of the cooperative's board of directors, which regulatory asset shall be approved by the Commission.
D. The participation of retail customers in a pilot program administered by a participating utility in the Commonwealth is in the public interest. Voluntary companion rate schedules approved by the Commission pursuant to this section are necessary in order to acquire information which is in furtherance of the public interest. The Commission shall approve the recovery of pilot program costs that it deems to be reasonable and prudent. The Commission shall also approve the pilot program design, the voluntary companion rate schedule, and the portfolio of participating generating facilities. No Commission review or approval of individual participating generating facilities, agreements, sites, or RFPs shall be required pursuant to this section or any other section of the Code.
E. Any voluntary companion rate schedule approved by the Commission pursuant to this section shall not be considered a tariff for electric energy provided 100 percent from renewable energy pursuant to § 56-577.
F. Each participating utility shall report on the status of its pilot program, including the number of subscribing customers, to the Governor, the Commission, and the Chairmen of the House and Senate Commerce and Labor Committees. The report shall be filed the earlier of (i) three years after the date a customer of the participating utility first subscribes to its pilot program or (ii) July 1, 2022. If a participating utility closes its pilot program to new subscribers pursuant to subdivision B 14, it shall notify the Governor, the Commission, and the Chairmen of the House and Senate Commerce and Labor Committees not later than three months after such closure, which notification shall (a) describe the reasons for the closure and (b) be provided in lieu of the status report otherwise required by this subsection.
G. At any time after filing its report on the status of its pilot program as required by subsection F, a participating utility may, in its application proceeding, move the Commission to make its pilot program permanent. The motion shall include a compliance filing with conforming changes to the participating utility's applicable rate schedules. Upon the Commission's granting of the motion, the pilot program shall become a regular rate schedule of the participating utility.
§56-585.3. Regulation of cooperative rates after rate caps.
A. After the expiration or termination of capped rates, the
rates, terms and conditions of distribution electric cooperatives subject to
Article 1 (§56-231.15 et seq.) of Chapter 9.1 of this title shall be
regulated in accordance with the provisions of Chapters 9.1 (§56-231.15 et
seq.) and 10 (§56-232 et seq.) of this title, as modified by the
following provisions:
1. Except for energy related cost (fuel cost), the Commission shall not require any cooperative to adjust, modify, or revise its rates, by means of riders or otherwise, to reflect changes in wholesale power cost which occurred during the capped rate period, other than in a general rate proceeding;
2. Each cooperative may, without Commission approval or the
requirement of any filing other than as provided in this subdivision, upon an
affirmative resolution of its board of directors, increase or decrease all
classes of its rates for distribution services at any time, provided, however,
that such adjustments will not effect a cumulative net increase or decrease in
excess of 5 five percent in such rates in any three year
three-year period. Such adjustments will not affect or be limited by any
existing fuel or wholesale power cost adjustment provisions. The cooperative
will promptly file any such revised rates with the Commission for informational
purposes;
3. Each cooperative may, without Commission approval, upon an affirmative resolution of its board of directors, make any adjustment to its terms and conditions that does not affect the cooperative's revenues from the distribution or supply of electric energy. In addition, a cooperative may make such adjustments to any pass-through of third-party service charges and fees, and to any fees, charges and deposits set out in Schedule F of such cooperative's Terms and Conditions filed as of January 1, 2007. The cooperative will promptly file any such amended terms and conditions with the Commission for informational purposes;
4. Each cooperative may, without Commission approval or the requirement of any filing other than as provided in this subdivision, upon an affirmative resolution of its board of directors, make any adjustment to its rates reasonably calculated to collect any or all of the fixed costs of owning and operating its electric distribution system, including without limitation, such costs as are identified as customer-related costs in a cost of service study, through a new or modified fixed monthly charge, rather than through volumetric charges associated with the use of electric energy or demand, or to rebalance among any of the fixed monthly charge, distribution demand, and distribution energy; however, such adjustments shall be revenue neutral based on the cooperative's determination of the proper intra-class allocation of the revenues produced by its then current rates. If a rate class contains a supply demand charge, the cooperative may rebalance its rate for electricity supply service pursuant to this subdivision. The cooperative may elect, but is not required, to implement such adjustments through incremental changes over the course of up to three years. The cooperative shall file promptly revised tariffs reflecting any such adjustments with the Commission for informational purposes; and
5. A cooperative may, at any time after the expiration or termination of capped rates, petition the Commission for approval of one or more rate adjustment clauses for the timely and current recovery from customers of the costs described in subdivisions A 5 b and e of §56-585.1.
B. None of the adjustments described in subdivisions A 2 through A 5 will apply to the rates paid by any customer that takes service by means of dedicated distribution facilities and had noncoincident peak demand in excess of 90 megawatts in calendar year 2006.
C. Nothing in this section shall be deemed to grant to a cooperative any authority to amend or adjust any terms and conditions of service or agreements regarding pole attachments or the use of the cooperative's poles or conduits.
§56-585.4. Net energy metering transition provisions for electric cooperatives.
Distribution electric cooperatives subject to Article 1 (§ 56-231.15 et seq.) of Chapter 9.1 shall be regulated in accordance with the provisions of Chapters 9.1 (§56-231.15 et seq.) and 10 (§56-232 et seq.), as amended by relevant sections of this chapter and by the following provisions:
1. Notwithstanding anything to the contrary in this title, each cooperative may, without Commission approval or the requirement of any filing other than as provided in this subdivision, upon the adoption by its board of directors of a resolution so providing, make adjustments in the cooperative's rates, terms, conditions, and rate schedules governing net energy metering as provided in this section by electing to subject itself to the provisions of this section. The cooperative promptly shall (i) file such resolution and notice with the Commission for informational purposes and (ii) place a notice of its board of directors' adoption of such resolution (the Cooperative Net Energy Metering Transition Notice) on the cooperative's website. The Cooperative Net Energy Metering Transition Notice shall contain an initial election date and a date upon which, for each class of net energy metering customer, the transition shall become effective upon the first to occur of (a) the date the cooperative reaches the cap set forth in subsection F of § 56-594.01 or (b) five years following the date of the initial Cooperative Net Energy Metering Transition Notice. If a cooperative transitions a given class of customers as a result of reaching a cap set forth in subsection F of § 56-594.01, the effectiveness of such transition shall be permanent, regardless of future changes in the cooperative's system peak. A Cooperative Net Energy Metering Transition Notice may be amended and refiled as the cooperative deems appropriate at any time. Any eligible customer-generator as defined in §56-594 that was interconnected prior to a transition start date enumerated in a Cooperative Net Energy Metering Transition Notice may continue to participate in net energy metering pursuant to the terms of §56-594.01 until July 1, 2039.
2. After the transition date for a class of customers, any standby charges implemented by the cooperative pursuant to subsection H of § 56-594.01 shall be eliminated and are prohibited. The cooperative may make any necessary changes to rate schedules or terms and conditions and shall promptly file the same with the Commission for informational purposes.
3. Whenever the cooperative's transition date occurs, the cooperative may establish and publish, without Commission approval or the requirement of any filing other than as provided in this subdivision, a new rate schedule or rider for purposes of its new net energy metering program established pursuant to this section and shall promptly file the same with the Commission for informational purposes.
4. The new rate schedule or rider described in subdivision 3 may contain a demand charge or charges for distribution, supply, or both, based upon a customer's monthly, ratcheted, or 60-minute absolute value noncoincident peak demand for customers that were not previously subject to demand charges in each rate class; however, such demand charges shall be revenue neutral based on the cooperative's determination of the proper intra-class allocation of the revenues produced by its then-current rates serving the same rate class of customer. The cooperative shall implement such new demand charge through the provisions of subdivision 5. The cooperative shall file promptly revised tariffs reflecting any such new demand charges with the Commission for informational purposes. The demand charge component of any net energy metering rate class derived from a rate class with a preexisting demand charge shall remain fixed for a period of five years. The fixed monthly customer charge of any net energy metering rate class derived from a preexisting rate class having a fixed monthly customer charge less than or equal to $20 as of the transition date shall not exceed $20 for the duration of the five-year period described in subdivision 5. During the five-year period described in subdivision 5, a cooperative may not increase the monthly customer charge of any net energy metering rate class derived from a preexisting rate class having a fixed monthly customer charge greater than $20 as of the transition date. Demand charges included in a new rate schedule or rider shall apply to net energy metering customers, regardless of whether a customer uses a third-party partial requirements power purchase agreement or not.
5. For purposes of implementing subdivision 4, a cooperative shall, after the published transition date for a given class of customers, close its existing net energy metering rate schedule rider to new customers and open a new tariff pursuant to subdivision 3. Demand charges shall be implemented over a five-year period. In the first year of the five-year period, the demand charges shall be set to zero. In the second year of the five-year period, implementation of the demand rates may begin, and demand charges shall not exceed $0.25 per kilowatt of distribution demand and $0.25 per kilowatt of supply demand. In the third year of the five-year period, the demand charges shall not exceed $0.50 per kilowatt of distribution demand and $0.50 per kilowatt of supply demand. In the fourth year of the five-year period, the demand charges shall not exceed $0.75 per kilowatt of distribution demand and $0.75 per kilowatt of supply demand. In the fifth year of the five-year period, the demand charges shall not exceed $1 per kilowatt of distribution demand and $1 per kilowatt of supply demand. Following the expiration of the five-year period, the cooperative is authorized to rebalance its rates. In any filing for informational purposes, the cooperative shall clearly set forth to the Commission the schedule for the five-year period.
6. After the transition date for a given class of customers, the following caps, which shall be in lieu of the caps established by subsection F of §56-594.01, shall apply to net energy metering for that class of customer. The caps shall be calculated as described in subsection F of §56-594.01 except that the caps shall be adjusted as follows, expressed in alternating current nameplate capacity of the generators: three percent of system peak for residential customers, four percent of system peak for not-for-profit and nonjurisdictional customers, and two percent for other nonresidential customers.
7. After the transition date for a given class of customers, only the following restrictions shall apply to the capacity of a net energy metering electrical generating facility:
a. For nonresidential customers, the maximum capacity shall not exceed the least of:
(1) 1.2 megawatts alternating current;
(2) One percent of the cooperative's system peak calculated according to the methodology described in subsection F of §56-594.01; or
(3) 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; and
b. For residential customers, the maximum capacity shall not exceed 125 percent of 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.
8. After the transition date for a given class of customers, third-party partial requirements power purchase agreements entered into with registered providers shall be permitted for that class of customer pursuant to subsection K of §56-594.01.
§56-594. Net energy metering provisions.
A. The Commission shall establish by regulation a program that affords eligible customer-generators the opportunity to participate in net energy metering, and a program, to begin no later than July 1, 2014, for customers of investor-owned utilities and to begin no later than July 1, 2015, and to end July 1, 2019, for customers of electric cooperatives as provided in subsection G, to afford eligible agricultural customer-generators the opportunity to participate in net energy metering. The regulations may include, but need not be limited to, requirements for (i) retail sellers; (ii) owners or operators of distribution or transmission facilities; (iii) providers of default service; (iv) eligible customer-generators; (v) eligible agricultural customer-generators; or (vi) any combination of the foregoing, as the Commission determines will facilitate the provision of net energy metering, provided that the Commission determines that such requirements do not adversely affect the public interest. On and after July 1, 2017, small agricultural generators or eligible agricultural customer-generators may elect to interconnect pursuant to the provisions of this section or as small agricultural generators pursuant to §56-594.2, but not both. Existing eligible agricultural customer-generators may elect to become small agricultural generators, but may not revert to being eligible agricultural customer-generators after such election. On and after July 1, 2019, interconnection of eligible agricultural customer-generators shall cease for electric cooperatives only, and such facilities shall interconnect solely as small agricultural generators. For electric cooperatives, eligible agricultural customer-generators whose renewable energy generating facilities were interconnected before July 1, 2019, may continue to participate in net energy metering pursuant to this section for a period not to exceed 25 years from the date of their renewable energy generating facility's original interconnection.
B. For the purpose of this section:
"Eligible agricultural customer-generator" means a customer that operates a renewable energy generating facility as part of an agricultural business, which generating facility (i) uses as its sole energy source solar power, wind power, or aerobic or anaerobic digester gas, (ii) does not have an aggregate generation capacity of more than 500 kilowatts, (iii) is located on land owned or controlled by the agricultural business, (iv) is connected to the customer's wiring on the customer's side of its interconnection with the distributor; (v) is interconnected and operated in parallel with an electric company's transmission and distribution facilities, and (vi) is used primarily to provide energy to metered accounts of the agricultural business. An eligible agricultural customer-generator may be served by multiple meters that are located at separate but contiguous sites, such that the eligible agricultural customer-generator may aggregate in a single account the electricity consumption and generation measured by the meters, provided that the same utility serves all such meters. The aggregated load shall be served under the appropriate tariff.
"Eligible customer-generator" means a customer that owns and operates, or contracts with other persons to own, operate, or both, an electrical generating facility that (i) has a capacity of not more than 20 kilowatts for residential customers and not more than one megawatt for nonresidential customers on an electrical generating facility placed in service after July 1, 2015; (ii) uses as its total source of fuel renewable energy, as defined in §56-576; (iii) is located on the customer's premises and is connected to the customer's wiring on the customer's side of its interconnection with the distributor; (iv) is interconnected and operated in parallel with an electric company's transmission and distribution facilities; and (v) is intended primarily to offset all or part of the customer's own electricity requirements. In addition to the electrical generating facility size limitations in clause (i), the capacity of any generating facility installed under this section 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.
"Net energy metering" means measuring the difference, over the net metering period, between (i) electricity supplied to an eligible customer-generator or eligible agricultural customer-generator from the electric grid and (ii) the electricity generated and fed back to the electric grid by the eligible customer-generator or eligible agricultural customer-generator.
"Net metering period" means the 12-month period following the date of final interconnection of the eligible customer-generator's or eligible agricultural customer-generator's system with an electric service provider, and each 12-month period thereafter.
"Small agricultural generator" has the same meaning that is ascribed to that term in §56-594.2.
C. The Commission's regulations shall ensure that (i) the metering equipment installed for net metering shall be capable of measuring the flow of electricity in two directions and (ii) any eligible customer-generator seeking to participate in net energy metering shall notify its supplier and receive approval to interconnect prior to installation of an electrical generating facility. The electric distribution company shall have 30 days from the date of notification for residential facilities, and 60 days from the date of notification for nonresidential facilities, to determine whether the interconnection requirements have been met. Such regulations shall allocate fairly the cost of such equipment and any necessary interconnection. An eligible customer-generator's electrical generating system, and each electrical generating system of an eligible agricultural customer-generator, shall 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. Beyond the requirements set forth in this section and to ensure public safety, power quality, and reliability of the supplier's electric distribution system, an eligible customer-generator or eligible agricultural customer-generator whose electrical generating system meets those standards and rules shall bear all reasonable costs of equipment required for the interconnection to the supplier's electric distribution system, including costs, if any, to (a) install additional controls, (b) perform or pay for additional tests, and (c) purchase additional liability insurance.
D. The Commission shall establish minimum requirements for contracts to be entered into by the parties to net metering arrangements. Such requirements shall protect the eligible customer-generator or eligible agricultural customer-generator against discrimination by virtue of its status as an eligible customer-generator or eligible agricultural customer-generator, and permit customers that are served on time-of-use tariffs that have electricity supply demand charges contained within the electricity supply portion of the time-of-use tariffs to participate as an eligible customer-generator or eligible agricultural customer-generator. Notwithstanding the cost allocation provisions of subsection C, eligible customer-generators or eligible agricultural customer-generators served on demand charge-based time-of-use tariffs shall bear the incremental metering costs required to net meter such customers.
E. If electricity generated by an eligible customer-generator
or eligible agricultural customer-generator over the net metering period
exceeds the electricity consumed by the eligible customer-generator or eligible
agricultural customer-generator, the customer-generator or eligible
agricultural customer-generator shall be compensated for the excess electricity
if the entity contracting to receive such electric energy and the eligible
customer-generator or eligible agricultural customer-generator enter into a
power purchase agreement for such excess electricity. Upon the written request
of the eligible customer-generator or eligible agricultural customer-generator,
the supplier that serves the eligible customer-generator or eligible
agricultural customer-generator shall enter into a power purchase agreement
with the requesting eligible customer-generator or eligible agricultural
customer-generator that is consistent with the minimum requirements for
contracts established by the Commission pursuant to subsection D. The power
purchase agreement shall obligate the supplier to purchase such excess
electricity at the rate that is provided for such purchases in a net metering
standard contract or tariff approved by the Commission, unless the parties
agree to a higher rate. The eligible customer-generator or eligible
agricultural customer-generator owns any renewable energy certificates
associated with its electrical generating facility; however, at the time that
the eligible customer-generator or eligible agricultural customer-generator
enters into a power purchase agreement with its supplier, the eligible
customer-generator or eligible agricultural customer-generator shall have a
one-time option to sell the renewable energy certificates associated with such
electrical generating facility to its supplier and be compensated at an amount
that is established by the Commission to reflect the value of such renewable
energy certificates. Nothing in this section shall prevent the eligible
customer-generator or eligible agricultural customer-generator and the supplier
from voluntarily entering into an agreement for the sale and purchase of excess
electricity or renewable energy certificates at mutually-agreed upon prices if
the eligible customer-generator or eligible agricultural customer-generator
does not exercise its option to sell its renewable energy certificates to its
supplier at Commission-approved prices at the time that the eligible
customer-generator or eligible agricultural customer-generator enters into a
power purchase agreement with its supplier. All costs incurred by the supplier
to purchase excess electricity and renewable energy certificates from eligible
customer-generators or eligible agricultural customer-generators shall be
recoverable through its Renewable Energy Portfolio Standard (RPS) rate
adjustment clause, if the supplier has a Commission-approved RPS plan. If not,
then all costs shall be recoverable through the supplier's fuel adjustment
clause. For purposes of this section, "all costs" shall be defined as
the rates paid to the eligible customer-generator or eligible agricultural
customer-generator for the purchase of excess electricity and renewable energy
certificates and any administrative costs incurred to manage the eligible
customer-generator's or eligible agricultural customer-generator's power
purchase arrangements. The net metering standard contract or tariff shall be
available to eligible customer-generators or eligible agricultural
customer-generators on a first-come, first-served basis in each electric
distribution company's Virginia service area until the rated generating
capacity owned and operated by eligible customer-generators, eligible agricultural
customer-generators, and small agricultural generators in the state
Commonwealth reaches one percent of each electric distribution company's
adjusted Virginia peak-load forecast for the previous year (the systemwide
cap), and shall require the supplier to pay the eligible customer-generator
or eligible agricultural customer-generator for such excess electricity in a
timely manner at a rate to be established by the Commission.
F. Any residential eligible customer-generator or eligible agricultural customer-generator who owns and operates, or contracts with other persons to own, operate, or both, an electrical generating facility with a capacity that exceeds 10 kilowatts shall pay to its supplier, in addition to any other charges authorized by law, a monthly standby charge. The amount of the standby charge and the terms and conditions under which it is assessed shall be in accordance with a methodology developed by the supplier and approved by the Commission. The Commission shall approve a supplier's proposed standby charge methodology if it finds that the standby charges collected from all such eligible customer-generators and eligible agricultural customer-generators allow the supplier to recover only the portion of the supplier's infrastructure costs that are properly associated with serving such eligible customer-generators or eligible agricultural customer-generators. Such an eligible customer-generator or eligible agricultural customer-generator shall not be liable for a standby charge until the date specified in an order of the Commission approving its supplier's methodology.
G. On and after the later of July 1, 2019, or the effective date of regulations that the Commission is required to adopt pursuant to § 56-594.01, (i) net energy metering in the service territory of each electric cooperative shall be conducted as provided in a program implemented pursuant to §56-594.01 and (ii) the provisions of this section shall not apply to net energy metering in the service territory of an electric cooperative except as provided in §56-594.01.
§56-594.01. Net energy metering provisions for electric cooperative service territories.
A. The Commission shall establish by regulation a program that affords eligible customer-generators the opportunity to participate in net energy metering in the service territory of each electric cooperative, which program shall commence on the later of July 1, 2019, or the effective date of such regulations. Such regulations shall be similar to existing regulations promulgated pursuant to §56-594. In lieu of adopting new regulations, the Commission may amend such existing regulations to apply to electric cooperatives with such revisions as are required to comply with the provisions of this section. The regulations may include requirements applicable to (i) retail sellers, (ii) owners or operators of distribution or transmission facilities, (iii) providers of default service, (iv) eligible customer-generators, or (v) any combination of the foregoing, as the Commission determines will facilitate the provision of net energy metering, provided that the Commission determines that such requirements do not adversely affect the public interest.
B. As used in this section:
"Eligible customer-generator" means a customer that owns and operates, or contracts with other persons to own, operate, or both, an electrical generating facility that (i) has a capacity of not more than 20 kilowatts for residential customers and not more than one megawatt for nonresidential customers on an electrical generating facility placed in service after July 1, 2015; (ii) uses as its total source of fuel renewable energy as defined in §56-576; (iii) is located on the customer's premises and is connected to the customer's wiring on the customer's side of its interconnection with the distributor; (iv) is interconnected and operated in parallel with an electric company's transmission and distribution facilities; and (v) is intended primarily to offset all or part of the customer's own electricity requirements. In addition to the electrical generating facility size limitations in clause (i), the capacity of any generating facility installed under this section 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.
"Net energy metering" means measuring the difference, over the net metering period, between (i) electricity supplied to an eligible customer-generator from the electric grid and (ii) the electricity generated and fed back to the electric grid by the eligible customer-generator.
"Net metering period" means the 12-month period following the date of final interconnection of the eligible customer-generator's system with an electric service provider, and each 12-month period thereafter.
C. The Commission's regulations shall ensure that (i) the metering equipment installed for net metering shall be capable of measuring the flow of electricity in two directions and (ii) any eligible customer-generator seeking to participate in net energy metering shall notify its supplier and receive approval to interconnect prior to installation of an electrical generating facility. The Commission shall publish a form for such prior notice and such notice shall be processed promptly by the supplier prior to any construction activity taking place. After construction, inspection and documentation thereof shall be required prior to interconnection. The electric distribution company shall have 30 days from the date of each notification for residential facilities, and 60 days from the date of each notification for nonresidential facilities, to determine whether the interconnection requirements have been met. Such regulations shall allocate fairly the cost of such equipment and any necessary interconnection. An eligible customer-generator's electrical generating system shall 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. In addition to the requirements set forth in this section and to ensure public safety, power quality, and reliability of the supplier's electric distribution system, an eligible customer-generator whose electrical generating system meets those standards and rules shall bear all reasonable costs of equipment required for the interconnection to the supplier's electric distribution system, including costs, if any, to (a) install additional controls, (b) perform or pay for additional tests, and (c) purchase additional liability insurance. An electric cooperative may publish and use its own forms, including an electronic form, for purposes of implementing the regulations described herein so long as the information collected on the Commission's form is also collected by the cooperative and submitted to the Commission.
D. The Commission shall establish minimum requirements for contracts to be entered into by the parties to net metering arrangements. Such requirements shall protect the eligible customer-generator against discrimination by virtue of its status as an eligible customer-generator and permit customers that are served on time-of-use tariffs that have electricity supply demand charges contained within the electricity supply portion of the time-of-use tariffs to participate as an eligible customer-generator. Notwithstanding the cost allocation provisions of subsection C, eligible customer-generators served on demand charge-based time-of-use tariffs shall bear the incremental metering costs required to net meter such customers.
E. If electricity generated by an eligible customer-generator over the net metering period exceeds the electricity consumed by the eligible customer-generator, the customer-generator shall be compensated for the excess electricity if the entity contracting to receive such electric energy and the eligible customer-generator enter into a power purchase agreement for such excess electricity. Upon the written request of the eligible customer-generator, the supplier that serves the eligible customer-generator shall enter into a power purchase agreement with the requesting eligible customer-generator that is consistent with the minimum requirements for contracts established by the Commission pursuant to subsection D. The power purchase agreement shall obligate the supplier to purchase such excess electricity at the rate that is provided for such purchases in a net metering standard contract or tariff approved by the Commission, unless the parties agree to a higher rate. The eligible customer-generator owns any renewable energy certificates associated with its electrical generating facility; however, at the time that the eligible customer-generator enters into a power purchase agreement with its supplier, the eligible customer-generator shall have a one-time option to sell the renewable energy certificates associated with such electrical generating facility to its supplier and be compensated at an amount that is established by the Commission to reflect the value of such renewable energy certificates. Nothing in this section shall prevent the eligible customer-generator and the supplier from voluntarily entering into an agreement for the sale and purchase of excess electricity or renewable energy certificates at mutually agreed upon prices if the eligible customer-generator does not exercise its option to sell its renewable energy certificates to its supplier at Commission-approved prices at the time that the eligible customer-generator enters into a power purchase agreement with its supplier. All costs incurred by the supplier to purchase excess electricity and renewable energy certificates from eligible customer-generators shall be recoverable through its fuel adjustment clause. For purposes of this section, "all costs" shall be defined as the rates paid to the eligible customer-generator for the purchase of excess electricity and renewable energy certificates and any administrative costs incurred to manage the eligible customer-generator's power purchase arrangements. The net metering standard contract or tariff shall be available to eligible customer-generators on a first-come, first-served basis, subject to the provisions of subsection F, and shall require the supplier to pay the eligible customer-generator for such excess electricity in a timely manner at a rate to be established by the Commission.
F. Net energy metering shall be open to customers on a first-come, first-served basis until such time as the total capacity of the generation facilities, expressed in alternating current nameplate, reaches two percent of system peak for residential customers, two percent of system peak for not-for-profit and nonjurisdictional customers, and one percent of system peak for other nonresidential customers, which are herein referred to as the electric cooperative's caps. As used in this subsection, "percent of system peak" refers to a percentage of the electric cooperative's highest total system peak, based on the noncoincident peak of the electric cooperative or the coincident peak of all of the electric cooperative's customers, within the past three years as listed in Part O, Line 20 of Form 7 filed with the Rural Utilities Service or its equivalent, less any portion of the cooperative's total load that is served by a competitive service provider or by a market-based rate. Such caps shall not decrease but may increase if the system peak in any year exceeds the previous year's system peak. Nothing in this subsection shall amend or confer new rights upon any existing nonjurisdictional contract or arrangement or work to submit any nonjurisdictional customer, contract, or arrangement to the jurisdiction of the Commission. For purposes of calculating the caps established in this subsection, all net energy metering shall be counted, whenever interconnected, and shall include net energy metering interconnected pursuant to §56-594, agricultural net energy metering, and any net energy metering entered into with a third-party provider registered pursuant to subsection K. Net energy metering with nonjurisdictional customers entered into prior to July 1, 2019, may be counted toward the caps, in the discretion of the cooperative, as net energy metering if the nonjurisdictional customer takes service pursuant to a cooperative's net energy metering rider. Net energy metering with nonjurisdictional customers entered into on or after July 1, 2019, shall be counted toward the caps by default unless the cooperative has reason to exclude such net energy metering as subject to a separate contract or arrangement. Each electric cooperative governed by this section shall publish information regarding the calculation and status of its caps pursuant to this subsection, or the electric cooperative's systemwide cap established in §56-585.4 if applicable, on the electric cooperative's website.
G. An electric cooperative may, without Commission approval or the requirement of any filing other than as provided in this subsection, upon the adoption by its board of directors of a resolution so providing, raise the caps established in subsection F up to a cumulative total of seven percent of system peak, calculated according to the methodology described in subsection F, with any increase allocated among residential, not-for-profit and nonjurisdictional, and other nonresidential customers as the board of directors may find to be in the interests of the electric cooperative's membership. The electric cooperative shall promptly file a revised net energy metering compliance filing with the Commission for informational purposes.
H. Any residential eligible customer-generator who owns and operates, or contracts with other persons to own, operate, or both, an electrical generating facility with a capacity that exceeds 10 kilowatts shall pay to its supplier, in addition to any other charges authorized by law, a monthly standby charge. The amount of the standby charge and the terms and conditions under which it is assessed shall be in accordance with a methodology developed by the supplier and approved by the Commission. The Commission shall approve a supplier's proposed standby charge methodology if it finds that the standby charges collected from all such eligible customer-generators allow the supplier to recover only the portion of the supplier's infrastructure costs that are properly associated with serving such eligible customer-generators. Such an eligible customer-generator shall not be liable for a standby charge until the date specified in an order of the Commission approving its supplier's methodology.
I. Any eligible agricultural customer-generator interconnected in an electric cooperative service territory prior to July 1, 2019, shall continue to be governed by §56-594 and the regulations adopted pursuant thereto throughout the grandfathering period described in subsection A of §56-594.
J. Any eligible customer-generator served by a competitive service provider pursuant to the provisions of §56-577 shall engage in net energy metering only with such supplier and pursuant only to tariffs filed by such supplier. Such an eligible customer-generator shall pay the full portion of its distribution charges, without offset or netting, to its electric cooperative.
K. After the conclusion of the Commission's rulemaking proceeding pursuant to subsection L, third-party partial requirements power purchase agreements, the purpose of which is to finance the purchase of renewable generation facilities by eligible customer-generators through the sale of electricity, shall be permitted pursuant to the provisions of this section only for those retail customers and nonjurisdictional customers of the electric cooperative that are exempt from federal income taxation, unless otherwise permitted by §56-585.4. No person shall offer a third-party partial requirements power purchase agreement in the service territory of an electric cooperative without fulfilling the registration requirements set forth in this section and complying with applicable Commission rules, including those adopted pursuant to subdivision L 2.
L. After August 1, 2019, but before January 1, 2020, the Commission shall initiate a rulemaking proceeding to promulgate the regulations necessary to implement this section as follows:
1. In conducting such a proceeding, the Commission may require notice to be given to current eligible customer-generators and eligible agricultural customer-generators but shall not require general publication of the notice. An opportunity to request a hearing shall be afforded, but a hearing is not required. In the rulemaking proceeding, the electric cooperatives governed by this section shall be required to submit compliance filings, but no other individual proceedings shall be required or conducted.
2. In promulgating regulations to govern third-party power purchase agreement providers as retail sellers, the Commission shall:
a. Direct the staff to administer a registration system for such providers;
b. Enumerate in its regulations the jurisdiction of the Commission over providers, generally limited in scope to the behavior of providers, customer complaints, and their compliance with the registration requirements and stating clearly that civil contract disputes and claims for damages against providers shall not be subject to the jurisdiction of the Commission;
c. Establish enumerate in its regulations the maximum extent of its authority over the providers, to be limited to any or all of:
(1) Monetary penalties against registered providers not to exceed $30,000 per provider registration;
(2) Orders for providers to cease or desist from a certain practice, act, or omission;
(3) Debarment of registered providers;
(4) The issuance of orders to show cause; and
(5) Authority incident to subdivisions (1) through (4);
d. Delineate in its regulations two classes of providers, one for residential customers and one for nonresidential customers;
e. Direct the staff to set up a self-certification system as described in this subdivision;
f. Establish business practice and consumer protection standards from a national renewable energy association whose business is germane to the businesses of the providers;
g. Require providers to comply with other applicable Commission regulations governing interconnection and safety, including utility procedures governing the same;
h. Require minimum capitalization or other bond or surety that, in the judgment of the Commission, is necessary for adequate consumer protection and in the public interest;
i. Require the payment of a fee of $250 for residential and nonresidential provider registration; and
j. Provide that no registered provider, by virtue of that status alone, shall be considered a public utility or competitive service provider for purposes of this title.
3. The self-certification system described in this subdivision shall require a provider to affirm to the staff, under the penalty of revocation of registration, (i) that it is licensed to do business in Virginia; (ii) the names of the responsible officers of the provider entity; (iii) that its named officers have no felony convictions or convictions for crimes of moral turpitude; (iv) that it will abide by all applicable Commission regulations promulgated under this section or for purposes of interconnections and safety; (v) that it will appoint an officer to be a primary liaison to the staff; (vi) that it will appoint an employee to be a primary contact for customer complaints; (vii) that it will have and disclose to customers a dispute resolution procedure; (viii) that it has specified in its registration materials in which territories it intends to offer power purchase agreements; (ix) that it, and each of its named officers, agree to submit themselves to the jurisdiction of the Commission as described in this subdivision; and (x) that, once registered, the provider shall report any material changes in its registration materials to the staff, as a continuing obligation of registration. The staff shall send a copy of the registration materials to each cooperative in whose territory the provider intends to offer power purchase agreements. The staff, once satisfied that the certifications required pursuant to this subdivision are complete, and not more than 30 days following the initial and complete submittal of the registration materials, shall enter the provider onto the official register of providers. No formal Commission proceeding is required for registration but may be initiated if the staff (a) has reason to doubt the veracity of the certifications of the provider or (b) in any other case, if, in the judgment of the staff, extenuating or extraordinary circumstances exist that warrant a proceeding. The staff shall not investigate the corporate structure, financing, bookkeeping, accounting practices, contracting practices, prices, or terms and conditions in a third-party partial requirements power purchase agreement. Nothing in this section shall abridge the right of any person, including the Office of Attorney General, from proceeding in a cause of action under the Virginia Consumer Protection Act, §59.1-196 et seq.
4. The Commission shall complete such rulemaking procedure within 12 months of its initiation.
2. That no later than 60 days after the effective date of this act each Phase II Utility, as such term is defined in subdivision A 1 of § 56-585.1 of the Code of Virginia, shall convene a stakeholder process to make recommendations to the utility concerning (i) the development of retail rate schedules designed to offer time-varying pricing that take advantage of advanced metering technology and related investments in customer information systems; (ii) the development of incentive programs for the installation of equipment to develop electric energy derived from sunlight for customers using advanced metering technology served under such time-varying rate schedules; (iii) the possible transition of net metering customers using advanced metering technology to the time-varying rate schedules; (iv) peak shaving programs; (v) the provision of on-site distributed renewable generation to multifamily dwellings; and (vi) related system effects and requirements arising from distributed generation resources. An independent facilitator with expertise in rate design, cost recovery, and solar markets, compensated by the utility, offset by such contributions from members of the stakeholder group as the members deem appropriate, shall facilitate such stakeholder process. The utility shall consult with the stakeholder group and the State Corporation Commission prior to engaging the independent facilitator. Such stakeholder process shall include representatives from the utility, the State Corporation Commission, the office of Consumer Counsel of the Attorney General, the Department of Mines, Minerals and Energy, net-metering program administrators, customer-generators, agricultural customer-generators, solar energy program implementers, solar energy providers, other residential and small business customers, and any other interested stakeholder who the utility deems appropriate for inclusion in such process. The utility shall report on the status of the work of the stakeholder group and the programs developed in conjunction with such stakeholder group, including the petitions filed and the determination thereon, to the Governor, the State Corporation Commission, and the Chairmen of the House and Senate Committees on Commerce and Labor on January 1, 2020, and thereafter on January 1 of each successive year. The scope of the work of the stakeholder group convened pursuant to this enactment shall include the following:
1. In developing the retail rate schedules designed to offer time-varying pricing that take advantage of advanced metering technology, the stakeholder group shall include at least one non-demand schedule.
2. In developing incentive programs for the installation of equipment to develop electric energy derived from sunlight for customers using advanced metering technology served under such time-varying rate schedules, the stakeholder group shall seek to accelerate solar development without adversely impacting other non-solar customers and to establish appropriate incentives to sustain the program, including consideration of the expiration of federal tax incentives available. Any such incentive program shall be limited to net-metering customers until other customers receive advanced metering technology.
3. In developing recommendations for the possible transition of net metering customers to the time-varying rate schedules, the stakeholder group shall (i) recommend the timing and increases in the net-metering cap to take advantage of the deployment of advanced metering technology and the approval of time-varying rate schedules, in a range estimated to be between two percent and four percent, and (ii) recommend appropriate increases in customer class caps, aligned with potential system cap increases, and the timing of deployment of advanced metering technology, taking into consideration infrastructure costs and rate impacts of higher solar distributed generation capacity. The stakeholder group shall recommend capacity and market milestones for growth of solar distributed generation capacity.
4. The stakeholder group shall develop recommendations related to distributed generation resources, including rate design options for the possible transition from retail net metering to successor time-varying rate schedules, recognizing the dependency of such rate design to the deployment of advanced metering technology. The stakeholder group design shall encourage rate stability and allow sufficient transition time for customer education. The stakeholder group shall seek to encourage voluntary transition to time-varying rate schedules and shall provide mechanisms to gather data from such early adopters in order to minimize program impacts on existing net metering customers and other ratepayers. The stakeholder group shall make recommendations about the appropriate grandfathering of existing net metering customers who elect not to be served under the time-varying rate schedules.
5. The stakeholder group may address the availability of power purchase agreements, standby and demand charges, Schedule 19 PURPA contracts, distributed generation storage deployment, and other topics that the facilitator deems appropriate.
3. That on or before March 1, 2020, a Phase II Utility, as such term is defined in subdivision A 1 of §56-585.1 of the Code of Virginia, shall develop and submit to the State Corporation Commission for approval retail rate schedules designed to offer time-varying pricing, including at least one non-demand rate schedule. Customer-generators or agricultural customer-generators participating in net metering may elect to be served under such time-varying rate schedule at such time as the customer-generator or agricultural customer-generator is served by advanced-metering technology equipment satisfactory to the utility.
4. That on or before March 1, 2020, a Phase II Utility, as such term is defined in subdivision A 1 of §56-585.1 of the Code of Virginia, shall develop and submit to the State Corporation Commission for approval an incentive program for the installation of equipment to develop electric energy derived from sunlight for customers served under time-varying retail rate schedules that have advanced-metering technology equipment satisfactory to the utility.
