Bill Text: VA HB1770 | 2023 | Regular Session | Prefiled
Bill Title: Virginia Electric Utility Regulation Act; retail competitiveness, review proceedings, etc.
Spectrum: Partisan Bill (Republican 1-0)
Status: (Passed) 2023-04-12 - Governor: Acts of Assembly Chapter text (CHAP0775) [HB1770 Detail]
Download: Virginia-2023-HB1770-Prefiled.html
Be it enacted by the General Assembly of Virginia:
1. That §§56-245.1:2, 56-577, 56-577.1, 56-585.1, 56-585.1:3, 56-585.1:4, and 56-599 of the Code of Virginia are amended and reenacted as follows:
§56-245.1:2. Customers to be notified of renewable power options.
A. The Commission shall post on its website the names,
telephone numbers, and available hyperlinks of suppliers of electric energy
licensed to sell retail electric energy pursuant to §56-587, that (i)
expressly state in their applications for licensure, or for any renewal
thereof, that they offer electric energy supplied from renewable energy standard eligible sources to
retail customers in the Commonwealth as described in subdivision A 5 3 a
of §56-577 and (ii) request in any such applications that they be identified
on the Commission's website as making such offers. Provided, however, that by
posting such information on its website, the Commission shall not be deemed to
provide any guarantees or assurances concerning the bona fides of such offers
or that any such offers are in conformance with the laws of the Commonwealth.
B. At least once each calendar quarter, each investor-owned electric utility in the Commonwealth shall include in or on the customer bills a notice directing them to the Commission website described in subsection A. Each investor-owned electric utility shall also feature available options for purchasing electric energy from renewable sources offered by the utility prominently on its website.
§56-577. Schedule for transition to retail competition; Commission authority; exemptions; pilot programs.
A. Retail competition for the purchase and sale of electric energy shall be subject to the following provisions:
1. Each incumbent electric utility owning, operating, controlling, or having an entitlement to transmission capacity shall join or establish a regional transmission entity, which entity may be an independent system operator, to which such utility shall transfer the management and control of its transmission system, subject to the provisions of §56-579.
2. The generation of electric energy shall be subject to regulation as specified in this chapter.
3. Subject to the
provisions of subdivisions 4 and 5,
only Only
individual retail customers of electric energy within the Commonwealth,
regardless of customer class, whose demand during the most recent calendar year
exceeded five megawatts but did not exceed one percent of the customer's
incumbent electric utility's peak load during the most recent calendar year
unless such customer had noncoincident peak demand in excess of 90 megawatts in
calendar year 2006 or any year thereafter, shall be permitted to purchase
electric energy from any supplier of electric energy licensed to sell retail
electric energy within the Commonwealth, except for any incumbent electric
utility other than the incumbent electric utility serving the exclusive service
territory in which such a customer is located, subject to the following
conditions:
a. Any such purchase from a licensed supplier shall be limited to the purchase of electric energy provided 100 percent from resources that qualify as a renewable energy standard eligible source applicable to the customer's incumbent electric utility pursuant to subsection C of §56-585.
b. The Commission shall only permit such a customer to purchase from a licensed supplier upon a finding by the Commission, pursuant to a petition filed by the customer, that neither the customer's incumbent electric utility nor retail customers of such utility that do not obtain electric energy from alternate suppliers will be adversely affected in a manner contrary to the public interest by granting such petition, and in making any such finding the Commission shall specifically consider any potential cost-shifting impacts to the utility's electric supply customers should the petition be granted.
c. If such customer does not purchase electric energy from licensed suppliers, such customer shall purchase electric energy from its incumbent electric utility.
b. Except as
provided in subdivision 4, the d. The demands
of individual retail customers may shall not be aggregated or
combined for the purpose of meeting the demand limitations of this provision,
any other provision of this chapter to the contrary notwithstanding. For the
purposes of this section, each noncontiguous site will nevertheless constitute
an individual retail customer even though one or more such sites may be under
common ownership of a single person.
c. e. If such customer does
purchase electric energy from licensed suppliers after the expiration or
termination of capped rates, it shall not thereafter be entitled to purchase
electric energy from the incumbent electric utility without giving five years'
advance written notice of such intention to such utility, except where such
customer demonstrates to the Commission, after notice and opportunity for
hearing, through clear and convincing evidence that its supplier has failed to
perform, or has anticipatorily breached its duty to perform, or otherwise is
about to fail to perform, through no fault of the customer, and that such
customer is unable to obtain service at reasonable rates from an alternative
supplier. If, as a result of such proceeding, the Commission finds it in the
public interest to grant an exemption from the five-year notice requirement,
such customer may thereafter purchase electric energy at the costs of such
utility, as determined by the Commission pursuant to subdivision 3 d hereof f,
for the remainder of the five-year notice period, after which point the
customer may purchase electric energy from the utility under rates, terms and
conditions determined pursuant to §56-585.1. However, such customer shall be
allowed to individually purchase electric energy from the utility under rates,
terms, and conditions determined pursuant to §56-585.1 if, upon application by
such customer, the Commission finds that neither such customer's incumbent
electric utility nor retail customers of such utility that do not choose to
obtain electric energy from alternate suppliers will be adversely affected in a
manner contrary to the public interest by granting such petition. In making
such determination, the Commission shall take into consideration, without
limitation, the impact and effect of any and all other previously approved
petitions of like type with respect to such incumbent electric utility. Any
customer that returns to purchase electric energy from its incumbent electric
utility, before or after expiration of the five-year notice period, shall be
subject to minimum stay periods equal to those prescribed by the Commission
pursuant to subdivision C 1.
d. f. The
costs of serving a customer that has received an exemption from the five-year
notice requirement under subdivision 3 c hereof e shall be the market-based
costs of the utility, including (i) the actual expenses of procuring such
electric energy from the market,; (ii) additional
administrative and transaction costs associated with procuring such energy,
including, but not limited
to, costs of transmission, transmission line losses, and
ancillary services,; and (iii) a reasonable margin
as determined pursuant to the provisions of subdivision A 2 of §56-585.1. The
methodology established by the Commission for determining such costs shall
ensure that neither utilities nor other retail customers are adversely affected
in a manner contrary to the public interest.
4. Two or more
individual nonresidential retail customers of electric energy within the
Commonwealth, whose individual demand during the most recent calendar year did
not exceed five megawatts, may petition the Commission for permission to
aggregate or combine their demands, for the purpose of meeting the demand
limitations of subdivision 3, so as to become qualified to purchase electric
energy from any supplier of electric energy licensed to sell retail electric
energy within the Commonwealth under the conditions specified in subdivision 3.
The Commission may, after notice and opportunity for hearing, approve such
petition if it finds that:
a. Neither such
customers' incumbent electric utility nor retail customers of such utility that
do not choose to obtain electric energy from alternate suppliers will be
adversely affected in a manner contrary to the public interest by granting such
petition. In making such determination, the Commission shall take into consideration,
without limitation, the impact and effect of any and all other previously
approved petitions of like type with respect to such incumbent electric
utility; and
b. Approval of such
petition is consistent with the public interest.
If such petition is
approved, all customers whose load has been aggregated or combined shall
thereafter be subject in all respects to the provisions of subdivision 3 and
shall be treated as a single, individual customer for the purposes of said
subdivision. In addition, the Commission shall impose reasonable periodic
monitoring and reporting obligations on such customers to demonstrate that they
continue, as a group, to meet the demand limitations of subdivision 3. If the
Commission finds, after notice and opportunity for hearing, that such group of
customers no longer meets the above demand limitations, the Commission may
revoke its previous approval of the petition, or take such other actions as may
be consistent with the public interest.
5. Individual retail
customers of electric energy within the Commonwealth, regardless of customer
class, shall be permitted:
a. To purchase
electric energy provided 100 percent from renewable energy from any supplier of
electric energy licensed to sell retail electric energy within the Commonwealth,
other than any incumbent electric utility that is not the incumbent electric
utility serving the exclusive service territory in which such a customer is
located, if the incumbent electric utility serving the exclusive service
territory does not offer an approved tariff for electric energy provided 100
percent from renewable energy; and
b. To continue
purchasing renewable energy pursuant to the terms of a power purchase agreement
in effect on the date there is filed with the Commission a tariff for the
incumbent electric utility that serves the exclusive service territory in which
the customer is located to offer electric energy provided 100 percent from
renewable energy, for the duration of such agreement Any individual retail customer of electric energy
within the Commonwealth that, prior to January
1, 2023, entered into an agreement
with a licensed supplier other than the incumbent electric utility to
purchase electric energy from such licensed supplier
pursuant to this section and that,
as of July, 2023, is no longer eligible under this section
to purchase electric energy from a supplier other than its incumbent electric
utility may continue to purchase electric
energy from such licensed supplier through the unexpired
term of such agreement. Such
customer shall purchase electric energy exclusively through its incumbent
utility following the expiration of such agreement.
6. 5. To the extent that an
incumbent electric utility has elected as of February 1, 2019, the Fixed
Resource Requirement alternative as a Load Serving Entity in the PJM Region and
continues to make such election and is therefore required to obtain capacity
for all load and expected load growth in its service area, any customer of a
utility subject to that requirement that purchases energy pursuant to
subdivision 3 or
4,
or pursuant to an aggregation petition approved
by the Commission prior to July 1, 2023,
from a supplier licensed to sell retail electric energy within the Commonwealth
shall continue to pay its incumbent electric utility for the non-fuel
generation capacity and transmission related costs incurred by the incumbent
electric utility in order to meet the customer's capacity obligations, pursuant
to the incumbent electric utility's standard tariff that has been approved by
and is on file with the Commission. In the case of such customer, the advance
written notice period established in subdivisions 3 c e and d f shall be three years. This
subdivision shall not apply to the customers of licensed suppliers that (i) had
an agreement with a licensed supplier entered into before February 1, 2019, or
(ii) had aggregation petitions pending before the Commission prior to January
1, 2019, unless and until any customer referenced in clause (i) or (ii) has
returned to purchase electric energy from its incumbent electric utility,
pursuant to the provisions of subdivision 3
or 4, and is receiving electric energy from such incumbent
electric utility.
7. 6. A tariff for one or more
classes of residential customers filed with the Commission for approval by a
cooperative on or after July 1, 2010, shall be deemed to offer a tariff for
electric energy provided 100 percent from renewable energy if it provides
undifferentiated electric energy and the cooperative retires a quantity of
renewable energy certificates equal to 100 percent of the electric energy
provided pursuant to such tariff. A tariff for one or more classes of
nonresidential customers filed with the Commission for approval by a
cooperative on or after July 1, 2012, shall be deemed to offer a tariff for
electric energy provided 100 percent from renewable energy if it provides
undifferentiated electric energy and the cooperative retires a quantity of
renewable energy certificates equal to 100 percent of the electric energy
provided pursuant to such tariff. For purposes of this section, "renewable
energy certificate" means, with respect to cooperatives, a tradable
commodity or instrument issued by a regional transmission entity or affiliate
or successor thereof in the United States that validates the generation of
electricity from renewable energy sources or that is certified under a
generally recognized renewable energy certificate standard. One renewable
energy certificate equals 1,000 kWh or one MWh of electricity generated from
renewable energy. A cooperative offering electric energy provided 100 percent
from renewable energy pursuant to this subdivision that involves the retirement
of renewable energy certificates shall disclose to its retail customers who
express an interest in purchasing energy pursuant to such tariff (i) that the
renewable energy is comprised of the retirement of renewable energy
certificates, (ii) the identity of the entity providing the renewable energy
certificates, and (iii) the sources of renewable energy being offered.
B. The Commission shall promulgate such rules and regulations as may be necessary to implement the provisions of this section.
C. 1. By January 1, 2002, the Commission shall promulgate regulations establishing whether and, if so, for what minimum periods, customers who request service from an incumbent electric utility pursuant to subsection D of §56-582 or a default service provider, after a period of receiving service from other suppliers of electric energy, shall be required to use such service from such incumbent electric utility or default service provider, as determined to be in the public interest by the Commission.
2. Subject to (i) the availability of capped rate service under §56-582, and (ii) the transfer of the management and control of an incumbent electric utility's transmission assets to a regional transmission entity after approval of such transfer by the Commission under §56-579, retail customers of such utility (a) purchasing such energy from licensed suppliers and (b) otherwise subject to minimum stay periods prescribed by the Commission pursuant to subdivision 1, shall nevertheless be exempt from any such minimum stay obligations by agreeing to purchase electric energy at the market-based costs of such utility or default providers after a period of obtaining electric energy from another supplier. Such costs shall include (i) the actual expenses of procuring such electric energy from the market, (ii) additional administrative and transaction costs associated with procuring such energy, including, but not limited to, costs of transmission, transmission line losses, and ancillary services, and (iii) a reasonable margin. The methodology of ascertaining such costs shall be determined and approved by the Commission after notice and opportunity for hearing and after review of any plan filed by such utility to procure electric energy to serve such customers. The methodology established by the Commission for determining such costs shall be consistent with the goals of (a) promoting the development of effective competition and economic development within the Commonwealth as provided in subsection A of §56-596, and (b) ensuring that neither incumbent utilities nor retail customers that do not choose to obtain electric energy from alternate suppliers are adversely affected.
3. Notwithstanding the provisions of subsection D of §56-582 and subsection C of §56-585, however, any such customers exempted from any applicable minimum stay periods as provided in subdivision 2 shall not be entitled to purchase retail electric energy thereafter from their incumbent electric utilities, or from any distributor required to provide default service under subsection B of §56-585, at the capped rates established under §56-582, unless such customers agree to satisfy any minimum stay period then applicable while obtaining retail electric energy at capped rates.
4. The Commission shall promulgate such rules and regulations as may be necessary to implement the provisions of this subsection, which rules and regulations shall include provisions specifying the commencement date of such minimum stay exemption program.
§56-577.1. Electric utilities; retail competition; pilot program.
A. The Commission shall conduct a pilot program under which
two or more nonresidential customers that, as of February 25, 2019, had filed
applications seeking to aggregate their load
pursuant to subdivision A 4 of §56-577 within the service
territory of a Phase II Utility, as that term is defined in subsection A of §
56-585.1, shall be permitted to purchase electric energy from any supplier of
electric energy licensed to sell electric energy within the Commonwealth,
subject to the following terms, conditions, and restrictions:
1. A pilot program shall be conducted within the certified service territory of the Phase II Utility in which such nonresidential customers are located.
2. The aggregated load participating in the pilot program shall not exceed 200 megawatts.
3. All customers participating in the pilot program shall be
subject in all respects to the provisions of subdivision A 3 of §56-577, with participation
in this pilot program being deemed to satisfy subdivision A 4 of §56-577 and
with the load set forth in each application being treated as a single,
individual customer for purposes of said subdivision,
and shall submit an annual report to the Commission by March 31 each year to
demonstrate that, for the preceding calendar year, such load continued to meet
the demand limitations of subdivision A 3 of §56-577.
B. The Commission shall review the pilot program established pursuant to subsection A in 2022.
§56-585.1. Generation, distribution, and transmission rates after capped rates terminate or expire.
A. During the first six months of 2009, the Commission shall, after notice and opportunity for hearing, initiate proceedings to review the rates, terms and conditions for the provision of generation, distribution and transmission services of each investor-owned incumbent electric utility. Such proceedings shall be governed by the provisions of Chapter 10 (§56-232 et seq.), except as modified herein. In such proceedings the Commission shall determine fair rates of return on common equity applicable to the generation and distribution services of the utility. In so doing, the Commission may use any methodology to determine such return it finds consistent with the public interest, but such return shall not be set lower than the average of the returns on common equity reported to the Securities and Exchange Commission for the three most recent annual periods for which such data are available by not less than a majority, selected by the Commission as specified in subdivision 2 b, of other investor-owned electric utilities in the peer group of the utility, nor shall the Commission set such return more than 300 basis points higher than such average. The peer group of the utility shall be determined in the manner prescribed in subdivision 2 b. The Commission may increase or decrease such combined rate of return by up to 100 basis points based on the generating plant performance, customer service, and operating efficiency of a utility, as compared to nationally recognized standards determined by the Commission to be appropriate for such purposes. In such a proceeding, the Commission shall determine the rates that the utility may charge until such rates are adjusted. If the Commission finds that the utility's combined rate of return on common equity is more than 50 basis points below the combined rate of return as so determined, it shall be authorized to order increases to the utility's rates necessary to provide the opportunity to fully recover the costs of providing the utility's services and to earn not less than such combined rate of return. If the Commission finds that the utility's combined rate of return on common equity is more than 50 basis points above the combined rate of return as so determined, it shall be authorized either (i) to order reductions to the utility's rates it finds appropriate, provided that the Commission may not order such rate reduction unless it finds that the resulting rates will provide the utility with the opportunity to fully recover its costs of providing its services and to earn not less than the fair rates of return on common equity applicable to the generation and distribution services; or (ii) to direct that 60 percent of the amount of the utility's earnings that were more than 50 basis points above the fair combined rate of return for calendar year 2008 be credited to customers' bills, in which event such credits shall be amortized over a period of six to 12 months, as determined at the discretion of the Commission, following the effective date of the Commission's order and be allocated among customer classes such that the relationship between the specific customer class rates of return to the overall target rate of return will have the same relationship as the last approved allocation of revenues used to design base rates. Commencing in 2011, the Commission, after notice and opportunity for hearing, shall conduct reviews of the rates, terms and conditions for the provision of generation, distribution and transmission services by each investor-owned incumbent electric utility, subject to the following provisions:
1. Rates, terms and conditions for each service shall be
reviewed separately on an unbundled basis, and such reviews shall be conducted
in a single, combined proceeding. Pursuant to subsection A of §56-585.1:1, the
Commission shall conduct a review for a Phase I Utility in
2020, utilizing the three successive 12-month test periods beginning
January 1, 2017, and ending December 31, 2019. Thereafter, reviews for a Phase I Utility will be
on a triennial basis
through 2023, with
subsequent such
proceedings utilizing the three successive 12-month
test periods ending December 31 immediately preceding the year in which such
review proceeding is conducted, and on a biennial
basis commencing in 2024, with such proceedings utilizing the two successive 12-month
test periods ending December 31 immediately preceding the year in which such
review proceeding is conducted,
except that the 2024 review
shall utilize the single 12-month test period
ending December 31, 2023. Pursuant to subsection A of §
56-585.1:1, the Commission shall conduct a review for a Phase II Utility in 2021, utilizing the four
successive 12-month test periods beginning January 1, 2017,
and ending December 31, 2020, with subsequent
reviews on a triennial biennial basis commencing in 2023, with such proceedings
utilizing the three two successive 12-month test
periods ending December 31 immediately preceding the year in which such review
proceeding is conducted. All such reviews
occurring after December 31, 2017, shall be referred to as triennial reviews.
For purposes of this section, a Phase I Utility is 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, and a Phase II Utility is an investor-owned incumbent electric
utility that was bound by such a settlement.
2. Subject to the provisions of subdivision 6, the fair rate
of return on common equity applicable separately to the generation and
distribution services of such utility, and for the two such services combined,
and for any rate adjustment clauses approved under subdivision 5 or 6, shall be
determined by the Commission during each such
triennial review, as follows:
a. The Commission may use any methodology to determine such
return it finds consistent with the public interest, but for applications
received by the Commission on or after January 1, 2020 July 1, 2023, such return
shall not be set lower than the average of
either (i) the returns on common
equity reported to the Securities and Exchange Commission for the three most
recent annual periods for which such data are available by not less than a
majority, selected by the Commission as specified in subdivision 2 b, of
other most recently authorized
returns on common equity or weighted cost of equity
set by the applicable
regulatory commissions for all
investor-owned electric utilities in the peer group of the utility subject to
such triennial review or (ii) the authorized returns on common equity
that are set by the applicable regulatory commissions for the same selected
peer group, nor shall the Commission set such return more
than 150 basis points higher than such average.
b. In selecting such
majority of peer group investor-owned electric utilities for applications
received by the Commission on or after January 1, 2020, the Commission shall
first remove from such group the two utilities within such group that have the
lowest reported or authorized, as applicable, returns of the group, as well as
the two utilities within such group that have the highest reported or
authorized, as applicable, returns of the group, and the Commission shall then
select a majority of the utilities remaining in such peer group. In its final
order regarding such triennial
review, the Commission shall identify the utilities in such peer group it
selected for the calculation of such limitation. For
purposes of this subdivision 2,
an investor-owned electric utility shall be deemed part of such peer group if
(i) its principal operations are conducted in the southeastern United States
east of the Mississippi River in either the states of West Virginia or Kentucky
or in those states south of Virginia, excluding the state of Tennessee, (ii) it
is a vertically-integrated electric utility providing generation, transmission, and distribution services to at least 200,000 retail electric customers
whose facilities and operations are subject to state public utility regulation
in the state where its principal operations are conducted, (iii) it had a
long-term bond rating assigned by Moody's Investors Service of at least Baa at
the end of the most recent test period subject to such
triennial review, and (iv) it is not an affiliate of the
utility subject to such triennial
review or a utility whose fair rate of return on common
equity is determined by the Commission.
c. The Commission may, consistent with its precedent for incumbent electric utilities prior to the enactment of Chapters 888 and 933 of the Acts of Assembly of 2007, increase or decrease the utility's combined rate of return based on the Commission's consideration of the utility's performance.
d. In any Current Proceeding, the Commission shall determine whether the Current Return has increased, on a percentage basis, above the Initial Return by more than the increase, expressed as a percentage, in the United States Average Consumer Price Index for all items, all urban consumers (CPI-U), as published by the Bureau of Labor Statistics of the United States Department of Labor, since the date on which the Commission determined the Initial Return. If so, the Commission may conduct an additional analysis of whether it is in the public interest to utilize such Current Return for the Current Proceeding then pending. A finding of whether the Current Return justifies such additional analysis shall be made without regard to any enhanced rate of return on common equity awarded pursuant to the provisions of subdivision 6. Such additional analysis shall include, but not be limited to, a consideration of overall economic conditions, the level of interest rates and cost of capital with respect to business and industry, in general, as well as electric utilities, the current level of inflation and the utility's cost of goods and services, the effect on the utility's ability to provide adequate service and to attract capital if less than the Current Return were utilized for the Current Proceeding then pending, and such other factors as the Commission may deem relevant. If, as a result of such analysis, the Commission finds that use of the Current Return for the Current Proceeding then pending would not be in the public interest, then the lower limit imposed by subdivision 2 a on the return to be determined by the Commission for such utility shall be calculated, for that Current Proceeding only, by increasing the Initial Return by a percentage at least equal to the increase, expressed as a percentage, in the United States Average Consumer Price Index for all items, all urban consumers (CPI-U), as published by the Bureau of Labor Statistics of the United States Department of Labor, since the date on which the Commission determined the Initial Return. For purposes of this subdivision:
"Current Proceeding" means any proceeding conducted under any provisions of this subsection that require or authorize the Commission to determine a fair combined rate of return on common equity for a utility and that will be concluded after the date on which the Commission determined the Initial Return for such utility.
"Current Return" means the minimum fair combined rate of return on common equity required for any Current Proceeding by the limitation regarding a utility's peer group specified in subdivision 2 a.
"Initial Return" means the fair combined rate of return on common equity determined for such utility by the Commission on the first occasion after July 1, 2009, under any provision of this subsection pursuant to the provisions of subdivision 2 a.
e. In addition to other considerations, in setting the return on equity within the range allowed by this section, the Commission shall strive to maintain costs of retail electric energy that are cost competitive with costs of retail electric energy provided by the other peer group investor-owned electric utilities.
f. The determination of such returns shall be made by the Commission on a stand-alone basis, and specifically without regard to any return on common equity or other matters determined with regard to facilities described in subdivision 6.
g. If the combined rate of return on common equity earned by the generation and distribution services is no more than 50 basis points above or below the return as so determined or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, such return is no more than 70 basis points above or below the return as so determined, such combined return shall not be considered either excessive or insufficient, respectively. However, for any test period commencing after December 31, 2012, for a Phase II Utility, and after December 31, 2013, for a Phase I Utility, if the utility has, during the test period or periods under review, earned below the return as so determined, whether or not such combined return is within 70 basis points of the return as so determined, the utility may petition the Commission for approval of an increase in rates in accordance with the provisions of subdivision 8 a as if it had earned more than 70 basis points below a fair combined rate of return, and such proceeding shall otherwise be conducted in accordance with the provisions of this section. The provisions of this subdivision are subject to the provisions of subdivision 8.
h. Any amount of a utility's earnings directed by the
Commission to be credited to customers' bills pursuant to this section shall
not be considered for the purpose of determining the utility's earnings in any
subsequent triennial
review.
3. Each such utility shall make a
triennial filing by March 31 of every third
year, with such filings commencing for a Phase I Utility in 2020 and terminating
after 2023, and such filings commencing for a Phase II
Utility in 2021,
consisting of the schedules contained in the Commission's rules governing
utility rate increase applications
and terminating thereafter. Such filing shall encompass the three successive 12-month test periods ending December
31 immediately preceding the year in which such proceeding is conducted, except
that the filing for a Phase II Utility in 2021
shall encompass the four successive 12-month test
periods ending December 31, 2020. After 2023, for a Phase I utility, and after
2021, for a Phase II Utility,
each such utility shall make a biennial filing by March
31 of every second year,
with such filings commencing for a Phase I Utility in 2024 and such filings
commencing for a Phase II Utility in 2023, except that the 2023 filing for a Phase
II Utility shall be made on or after July 1, 2023. All
biennial filings shall encompass the two successive
12-month test periods ending December 31 immediately preceding the year in
which such review proceeding is conducted,
except that the 2024 review
shall utilize the single 12-month test period ending December 31, 2023. All
such filings shall consist of the schedules contained in the Commission's rules
governing utility rate increase applications, and in every
such case the filing for each year shall be identified separately and shall be
segregated from any other year encompassed by the filing.
In a filing under this subdivision that does not result in an overall rate
change, a utility may
propose an adjustment to one or more tariffs that are revenue neutral to the
utility.
If the Commission determines that rates should be revised or
credits be applied to customers' bills pursuant to subdivision 8 or 9
10, any rate adjustment clauses previously implemented
related to facilities utilizing simple-cycle combustion turbines described in
subdivision 6, shall be combined with the utility's costs, revenues and investments
until the amounts that are the subject of such rate adjustment clauses are
fully recovered. The Commission shall combine such clauses with the utility's
costs, revenues and investments only after it makes its initial determination
with regard to necessary rate revisions or credits to customers' bills, and the
amounts thereof, but after such clauses are combined as
herein specified in this paragraph,
they shall thereafter be considered part of the utility's costs, revenues, and
investments for the purposes of future triennial
review proceedings. In a
triennial filing under this subdivision that does not result
in an overall rate change a utility may propose an adjustment to one or more
tariffs that are revenue neutral to the utility.
In any biennial review filed by a Phase II Utility in 2023, such utility shall combine rate adjustment clauses previously implemented pursuant to subdivision 5 or 6 having a combined annual revenue requirement, as of July 1, 2023, of at least $300 million with the utility's costs, revenues, and investments for generation and distribution services. After such rate adjustment clauses are combined as specified in this paragraph, such rate adjustment clauses shall be considered part of the utility's costs, revenues, and investments for the purposes of future biennial review proceedings, and the combination of such rate adjustment clauses shall be specifically subject to audit by the Commission in the utility's 2023 biennial review filing.
4. (Expires December 31, 2023) The following costs incurred by the utility shall be deemed reasonable and prudent: (i) costs for transmission services provided to the utility by the regional transmission entity of which the utility is a member, as determined under applicable rates, terms and conditions approved by the Federal Energy Regulatory Commission; (ii) costs charged to the utility that are associated with demand response programs approved by the Federal Energy Regulatory Commission and administered by the regional transmission entity of which the utility is a member; and (iii) costs incurred by the utility to construct, operate, and maintain transmission lines and substations installed in order to provide service to a business park. Upon petition of a utility at any time after the expiration or termination of capped rates, but not more than once in any 12-month period, the Commission shall approve a rate adjustment clause under which such costs, including, without limitation, costs for transmission service; charges for new and existing transmission facilities, including costs incurred by the utility to construct, operate, and maintain transmission lines and substations installed in order to provide service to a business park; administrative charges; and ancillary service charges designed to recover transmission costs, shall be recovered on a timely and current basis from customers. Retail rates to recover these costs shall be designed using the appropriate billing determinants in the retail rate schedules.
4. (Effective January 1, 2024) The following costs incurred by the utility shall be deemed reasonable and prudent: (i) costs for transmission services provided to the utility by the regional transmission entity of which the utility is a member, as determined under applicable rates, terms and conditions approved by the Federal Energy Regulatory Commission, and (ii) costs charged to the utility that are associated with demand response programs approved by the Federal Energy Regulatory Commission and administered by the regional transmission entity of which the utility is a member. Upon petition of a utility at any time after the expiration or termination of capped rates, but not more than once in any 12-month period, the Commission shall approve a rate adjustment clause under which such costs, including, without limitation, costs for transmission service, charges for new and existing transmission facilities, administrative charges, and ancillary service charges designed to recover transmission costs, shall be recovered on a timely and current basis from customers. Retail rates to recover these costs shall be designed using the appropriate billing determinants in the retail rate schedules.
5. A utility may at any time, after the expiration or termination of capped rates, but not more than once in any 12-month period, petition the Commission for approval of one or more rate adjustment clauses for the timely and current recovery from customers of the following costs:
a. Incremental costs described in clause (vi) of subsection B of §56-582 incurred between July 1, 2004, and the expiration or termination of capped rates, if such utility is, as of July 1, 2007, deferring such costs consistent with an order of the Commission entered under clause (vi) of subsection B of §56-582. The Commission shall approve such a petition allowing the recovery of such costs that comply with the requirements of clause (vi) of subsection B of §56-582;
b. Projected and actual costs for the utility to design and operate fair and effective peak-shaving programs or pilot programs. The Commission shall approve such a petition if it finds that the program is in the public interest, provided that the Commission shall allow the recovery of such costs as it finds are reasonable;
c. Projected and actual costs for the utility to design, implement, and operate energy efficiency programs or pilot programs. Any such petition shall include a proposed budget for the design, implementation, and operation of the energy efficiency program, including anticipated savings from and spending on each program, and the Commission shall grant a final order on such petitions within eight months of initial filing. The Commission shall only approve such a petition if it finds that the program is in the public interest. If the Commission determines that an energy efficiency program or portfolio of programs is not in the public interest, its final order shall include all work product and analysis conducted by the Commission's staff in relation to that program that has bearing upon the Commission's determination. Such order shall adhere to existing protocols for extraordinarily sensitive information.
Energy efficiency pilot programs are in the public interest provided that the pilot program is (i) of limited scope, cost, and duration and (ii) intended to determine whether a new or substantially revised program would be cost-effective.
Prior to January 1, 2022, the Commission shall award a margin for recovery on operating expenses for energy efficiency programs and pilot programs, which margin shall be equal to the general rate of return on common equity determined as described in subdivision 2. Beginning January 1, 2022, and thereafter, if the Commission determines that the utility meets in any year the annual energy efficiency standards set forth in §56-596.2, in the following year, the Commission shall award a margin on energy efficiency program operating expenses in that year, to be recovered through a rate adjustment clause, which margin shall be equal to the general rate of return on common equity determined as described in subdivision 2. If the Commission does not approve energy efficiency programs that, in the aggregate, can achieve the annual energy efficiency standards, the Commission shall award a margin on energy efficiency operating expenses in that year for any programs the Commission has approved, to be recovered through a rate adjustment clause under this subdivision, which margin shall equal the general rate of return on common equity determined as described in subdivision 2. Any margin awarded pursuant to this subdivision shall be applied as part of the utility's next rate adjustment clause true-up proceeding. The Commission shall also award an additional 20 basis points for each additional incremental 0.1 percent in annual savings in any year achieved by the utility's energy efficiency programs approved by the Commission pursuant to this subdivision, beyond the annual requirements set forth in §56-596.2, provided that the total performance incentive awarded in any year shall not exceed 10 percent of that utility's total energy efficiency program spending in that same year.
The Commission shall annually monitor and report to the General Assembly the performance of all programs approved pursuant to this subdivision, including each utility's compliance with the total annual savings required by §56-596.2, as well as the annual and lifecycle net and gross energy and capacity savings, related emissions reductions, and other quantifiable benefits of each program; total customer bill savings that the programs produce; utility spending on each program, including any associated administrative costs; and each utility's avoided costs and cost-effectiveness results.
Notwithstanding any other provision of law, unless the Commission finds in its discretion and after consideration of all in-state and regional transmission entity resources that there is a threat to the reliability or security of electric service to the utility's customers, the Commission shall not approve construction of any new utility-owned generating facilities that emit carbon dioxide as a by-product of combusting fuel to generate electricity unless the utility has already met the energy savings goals identified in §56-596.2 and the Commission finds that supply-side resources are more cost-effective than demand-side or energy storage resources.
As used in this subdivision, "large general service customer" means a customer that has a verifiable history of having used more than one megawatt of demand from a single site.
Large general service customers shall be exempt from requirements that they participate in energy efficiency programs if the Commission finds that the large general service customer has, at the customer's own expense, implemented energy efficiency programs that have produced or will produce measured and verified results consistent with industry standards and other regulatory criteria stated in this section. The Commission shall, no later than June 30, 2021, adopt rules or regulations (a) establishing the process for large general service customers to apply for such an exemption, (b) establishing the administrative procedures by which eligible customers will notify the utility, and (c) defining the standard criteria that shall be satisfied by an applicant in order to notify the utility, including means of evaluation measurement and verification and confidentiality requirements. At a minimum, such rules and regulations shall require that each exempted large general service customer certify to the utility and Commission that its implemented energy efficiency programs have delivered measured and verified savings within the prior five years. In adopting such rules or regulations, the Commission shall also specify the timing as to when a utility shall accept and act on such notice, taking into consideration the utility's integrated resource planning process, as well as its administration of energy efficiency programs that are approved for cost recovery by the Commission. Savings from large general service customers shall be accounted for in utility reporting in the standards in §56-596.2.
The notice of nonparticipation by a large general service customer shall be for the duration of the service life of the customer's energy efficiency measures. The Commission may on its own motion initiate steps necessary to verify such nonparticipant's achievement of energy efficiency if the Commission has a body of evidence that the nonparticipant has knowingly misrepresented its energy efficiency achievement.
A utility shall not charge such large general service customer for the costs of installing energy efficiency equipment beyond what is required to provide electric service and meter such service on the customer's premises if the customer provides, at the customer's expense, equivalent energy efficiency equipment. In all relevant proceedings pursuant to this section, the Commission shall take into consideration the goals of economic development, energy efficiency and environmental protection in the Commonwealth;
d. Projected and actual costs of compliance with renewable energy portfolio standard requirements pursuant to §56-585.5 that are not recoverable under subdivision 6. The Commission shall approve such a petition allowing the recovery of such costs incurred as required by §56-585.5, provided that the Commission does not otherwise find such costs were unreasonably or imprudently incurred;
e. Projected and actual costs of projects that the Commission finds to be necessary to mitigate impacts to marine life caused by construction of offshore wind generating facilities, as described in §56-585.1:11, or to comply with state or federal environmental laws or regulations applicable to generation facilities used to serve the utility's native load obligations, including the costs of allowances purchased through a market-based trading program for carbon dioxide emissions. The Commission shall approve such a petition if it finds that such costs are necessary to comply with such environmental laws or regulations;
f. Projected and actual costs, not currently in rates, for the utility to design, implement, and operate programs approved by the Commission that accelerate the vegetation management of distribution rights-of-way. No costs shall be allocated to or recovered from customers that are served within the large general service rate classes for a Phase II Utility or that are served at subtransmission or transmission voltage, or take delivery at a substation served from subtransmission or transmission voltage, for a Phase I Utility; and
g. Projected and actual costs, not currently in rates, for the utility to design, implement, and operate programs approved by the Commission to provide incentives to (i) low-income, elderly, and disabled individuals or (ii) organizations providing residential services to low-income, elderly, and disabled individuals for the installation of, or access to, equipment to generate electric energy derived from sunlight, provided the low-income, elderly, and disabled individuals, or organizations providing residential services to low-income, elderly, and disabled individuals, first participate in incentive programs for the installation of measures that reduce heating or cooling costs.
Any rate adjustment clause approved under subdivision 5 c by the Commission shall remain in effect until the utility exhausts the approved budget for the energy efficiency program. The Commission shall have the authority to determine the duration or amortization period for any other rate adjustment clause approved under this subdivision.
6. To ensure the generation and delivery of a reliable and adequate supply of electricity, to meet the utility's projected native load obligations and to promote economic development, a utility may at any time, after the expiration or termination of capped rates, petition the Commission for approval of a rate adjustment clause for recovery on a timely and current basis from customers of the costs of (i) a coal-fueled generation facility that utilizes Virginia coal and is located in the coalfield region of the Commonwealth as described in §15.2-6002, regardless of whether such facility is located within or without the utility's service territory, (ii) one or more other generation facilities, (iii) one or more major unit modifications of generation facilities, including the costs of any system or equipment upgrade, system or equipment replacement, or other cost reasonably appropriate to extend the combined operating license for or the operating life of one or more generation facilities utilizing nuclear power, (iv) one or more new underground facilities to replace one or more existing overhead distribution facilities of 69 kilovolts or less located within the Commonwealth, (v) one or more pumped hydroelectricity generation and storage facilities that utilize on-site or off-site renewable energy resources as all or a portion of their power source and such facilities and associated resources are located in the coalfield region of the Commonwealth as described in §15.2-6002, regardless of whether such facility is located within or without the utility's service territory, or (vi) one or more electric distribution grid transformation projects; however, subject to the provisions of the following sentence, the utility shall not file a petition under clause (iv) more often than annually and, in such petition, shall not seek any annual incremental increase in the level of investments associated with such a petition that exceeds five percent of such utility's distribution rate base, as such rate base was determined for the most recently ended 12-month test period in the utility's latest review proceeding conducted pursuant to subdivision 3 and concluded by final order of the Commission prior to the date of filing of such petition under clause (iv). In all proceedings regarding petitions filed under clause (iv) or (vi), the level of investments approved for recovery in such proceedings shall be in addition to, and not in lieu of, levels of investments previously approved for recovery in prior proceedings under clause (iv) or (vi), as applicable. As of December 1, 2028, any costs recovered by a utility pursuant to clause (iv) shall be limited to any remaining costs associated with conversions of overhead distribution facilities to underground facilities that have been previously approved or are pending approval by the Commission through a petition by the utility under this subdivision. Such a petition concerning facilities described in clause (ii) that utilize nuclear power, facilities described in clause (ii) that are coal-fueled and will be built by a Phase I Utility, or facilities described in clause (i) may also be filed before the expiration or termination of capped rates. A utility that constructs or makes modifications to any such facility, or purchases any facility consisting of at least one megawatt of generating capacity using energy derived from sunlight and located in the Commonwealth and that utilizes goods or services sourced, in whole or in part, from one or more Virginia businesses, shall have the right to recover the costs of the facility, as accrued against income, through its rates, including projected construction work in progress, and any associated allowance for funds used during construction, planning, development and construction or acquisition costs, life-cycle costs, costs related to assessing the feasibility of potential sites for new underground facilities, and costs of infrastructure associated therewith, plus, as an incentive to undertake such projects, an enhanced rate of return on common equity calculated as specified below; however, in determining the amounts recoverable under a rate adjustment clause for new underground facilities, the Commission shall not consider, or increase or reduce such amounts recoverable because of (a) the operation and maintenance costs attributable to either the overhead distribution facilities being replaced or the new underground facilities or (b) any other costs attributable to the overhead distribution facilities being replaced. Notwithstanding the preceding sentence, the costs described in clauses (a) and (b) thereof shall remain eligible for recovery from customers through the utility's base rates for distribution service. A utility filing a petition for approval to construct or purchase a facility consisting of at least one megawatt of generating capacity using energy derived from sunlight and located in the Commonwealth and that utilizes goods or services sourced, in whole or in part, from one or more Virginia businesses may propose a rate adjustment clause based on a market index in lieu of a cost of service model for such facility. A utility seeking approval to construct or purchase a generating facility that emits carbon dioxide shall demonstrate that it has already met the energy savings goals identified in §56-596.2 and that the identified need cannot be met more affordably through the deployment or utilization of demand-side resources or energy storage resources and that it has considered and weighed alternative options, including third-party market alternatives, in its selection process.
The costs of the facility, other than return on projected construction work in progress and allowance for funds used during construction, shall not be recovered prior to the date a facility constructed by the utility and described in clause (i), (ii), (iii), or (v) begins commercial operation, the date the utility becomes the owner of a purchased generation facility consisting of at least one megawatt of generating capacity using energy derived from sunlight and located in the Commonwealth and that utilizes goods or services sourced, in whole or in part, from one or more Virginia businesses, or the date new underground facilities are classified by the utility as plant in service. In any application to construct a new generating facility, the utility shall include, and the Commission shall consider, the social cost of carbon, as determined by the Commission, as a benefit or cost, whichever is appropriate. The Commission shall ensure that the development of new, or expansion of existing, energy resources or facilities does not have a disproportionate adverse impact on historically economically disadvantaged communities. The Commission may adopt any rules it deems necessary to determine the social cost of carbon and shall use the best available science and technology, including the Technical Support Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866, published by the Interagency Working Group on Social Cost of Greenhouse Gases from the United States Government in August 2016, as guidance. The Commission shall include a system to adjust the costs established in this section with inflation.
Such enhanced rate of return on common equity shall be applied to allowance for funds used during construction and to construction work in progress during the construction phase of the facility and shall thereafter be applied to the entire facility during the first portion of the service life of the facility. The first portion of the service life shall be as specified in the table below; however, the Commission shall determine the duration of the first portion of the service life of any facility, within the range specified in the table below, which determination shall be consistent with the public interest and shall reflect the Commission's determinations regarding how critical the facility may be in meeting the energy needs of the citizens of the Commonwealth and the risks involved in the development of the facility. After the first portion of the service life of the facility is concluded, the utility's general rate of return shall be applied to such facility for the remainder of its service life. As used herein, the service life of the facility shall be deemed to begin on the date a facility constructed by the utility and described in clause (i), (ii), (iii), or (v) begins commercial operation, the date the utility becomes the owner of a purchased generation facility consisting of at least one megawatt of generating capacity using energy derived from sunlight and located in the Commonwealth and that utilizes goods or services sourced, in whole or in part, from one or more Virginia businesses, or the date new underground facilities or new electric distribution grid transformation projects are classified by the utility as plant in service, and such service life shall be deemed equal in years to the life of that facility as used to calculate the utility's depreciation expense. Such enhanced rate of return on common equity shall be calculated by adding the basis points specified in the table below to the utility's general rate of return, and such enhanced rate of return shall apply only to the facility that is the subject of such rate adjustment clause. Allowance for funds used during construction shall be calculated for any such facility utilizing the utility's actual capital structure and overall cost of capital, including an enhanced rate of return on common equity as determined pursuant to this subdivision, until such construction work in progress is included in rates. The construction of any facility described in clause (i) or (v) is in the public interest, and in determining whether to approve such facility, the Commission shall liberally construe the provisions of this title. The construction or purchase by a utility of one or more generation facilities with at least one megawatt of generating capacity, and with an aggregate rated capacity that does not exceed 16,100 megawatts, including rooftop solar installations with a capacity of not less than 50 kilowatts, and with an aggregate capacity of 100 megawatts, that use energy derived from sunlight or from onshore wind and are located in the Commonwealth or off the Commonwealth's Atlantic shoreline, regardless of whether any of such facilities are located within or without the utility's service territory, is in the public interest, and in determining whether to approve such facility, the Commission shall liberally construe the provisions of this title. A utility may enter into short-term or long-term power purchase contracts for the power derived from sunlight generated by such generation facility prior to purchasing the generation facility. The replacement of any subset of a utility's existing overhead distribution tap lines that have, in the aggregate, an average of nine or more total unplanned outage events-per-mile over a preceding 10-year period with new underground facilities in order to improve electric service reliability is in the public interest. In determining whether to approve petitions for rate adjustment clauses for such new underground facilities that meet this criteria, and in determining the level of costs to be recovered thereunder, the Commission shall liberally construe the provisions of this title.
The conversion of any such facilities on or after September 1, 2016, is deemed to provide local and system-wide benefits and to be cost beneficial, and the costs associated with such new underground facilities are deemed to be reasonably and prudently incurred and, notwithstanding the provisions of subsection C or D, shall be approved for recovery by the Commission pursuant to this subdivision, provided that the total costs associated with the replacement of any subset of existing overhead distribution tap lines proposed by the utility with new underground facilities, exclusive of financing costs, shall not exceed an average cost per customer of $20,000, with such customers, including those served directly by or downline of the tap lines proposed for conversion, and, further, such total costs shall not exceed an average cost per mile of tap lines converted, exclusive of financing costs, of $750,000. A utility shall, without regard for whether it has petitioned for any rate adjustment clause pursuant to clause (vi), petition the Commission, not more than once annually, for approval of a plan for electric distribution grid transformation projects. Any plan for electric distribution grid transformation projects shall include both measures to facilitate integration of distributed energy resources and measures to enhance physical electric distribution grid reliability and security. In ruling upon such a petition, the Commission shall consider whether the utility's plan for such projects, and the projected costs associated therewith, are reasonable and prudent. Such petition shall be considered on a stand-alone basis without regard to the other costs, revenues, investments, or earnings of the utility; without regard to whether the costs associated with such projects will be recovered through a rate adjustment clause under this subdivision or through the utility's rates for generation and distribution services; and without regard to whether such costs will be the subject of a customer credit offset, as applicable, pursuant to subdivision 8 d. The Commission's final order regarding any such petition for approval of an electric distribution grid transformation plan shall be entered by the Commission not more than six months after the date of filing such petition. The Commission shall likewise enter its final order with respect to any petition by a utility for a certificate to construct and operate a generating facility or facilities utilizing energy derived from sunlight, pursuant to subsection D of §56-580, within six months after the date of filing such petition. The basis points to be added to the utility's general rate of return to calculate the enhanced rate of return on common equity, and the first portion of that facility's service life to which such enhanced rate of return shall be applied, shall vary by type of facility, as specified in the following table:
|
Type of Generation Facility |
Basis Points |
First Portion of Service Life |
|
|
Nuclear-powered |
200 |
Between 12 and 25 years |
|
|
Carbon capture compatible, clean-coal powered |
200 |
Between 10 and 20 years |
|
|
Renewable powered, other than landfill gas powered |
200 |
Between 5 and 15 years |
|
|
Coalbed methane gas powered |
150 |
Between 5 and 15 years |
|
|
Landfill gas powered |
200 |
Between 5 and 15 years |
|
|
Conventional coal or combined-cycle combustion turbine |
100 |
Between 10 and 20 years |
Only those facilities as to which a rate adjustment clause under this subdivision has been previously approved by the Commission, or as to which a petition for approval of such rate adjustment clause was filed with the Commission, on or before January 1, 2013, shall be entitled to the enhanced rate of return on common equity as specified in the above table during the construction phase of the facility and the approved first portion of its service life.
Thirty percent of all costs of such a facility utilizing nuclear power that the utility incurred between July 1, 2007, and December 31, 2013, and all of such costs incurred after December 31, 2013, may be deferred by the utility and recovered through a rate adjustment clause under this subdivision at such time as the Commission provides in an order approving such a rate adjustment clause. The remaining 70 percent of all costs of such a facility that the utility incurred between July 1, 2007, and December 31, 2013, shall not be deferred for recovery through a rate adjustment clause under this subdivision; however, such remaining 70 percent of all costs shall be recovered ratably through existing base rates as determined by the Commission in the test periods under review in the utility's next review filed after July 1, 2014. Thirty percent of all costs of a facility utilizing energy derived from offshore wind that the utility incurred between July 1, 2007, and December 31, 2013, and all of such costs incurred after December 31, 2013, may be deferred by the utility and recovered through a rate adjustment clause under this subdivision at such time as the Commission provides in an order approving such a rate adjustment clause. The remaining 70 percent of all costs of such a facility that the utility incurred between July 1, 2007, and December 31, 2013, shall not be deferred for recovery through a rate adjustment clause under this subdivision; however, such remaining 70 percent of all costs shall be recovered ratably through existing base rates as determined by the Commission in the test periods under review in the utility's next review filed after July 1, 2014.
In connection with planning to meet forecasted demand for electric generation supply and assure the adequate and sufficient reliability of service, consistent with §56-598, planning and development activities for a new utility-owned and utility-operated generating facility or facilities utilizing energy derived from sunlight or from onshore or offshore wind are in the public interest.
Notwithstanding any provision of Chapter 296 of the Acts of
Assembly of 2018, construction, purchasing, or leasing activities for a new
utility-owned and utility-operated generating facility or facilities utilizing
energy derived from sunlight or from onshore wind with an aggregate capacity of
16,100 megawatts, including rooftop solar installations with a capacity of not
less than 50 kilowatts, and with an aggregate capacity of 100 megawatts,
together with a utility-owned and utility-operated generating facility or
facilities utilizing energy derived from offshore wind with an aggregate
capacity of not more than 3,000 megawatts, are in the public interest.
Additionally, energy storage facilities with an aggregate capacity of 2,700
megawatts are in the public interest. To the extent that a utility elects to
recover the costs of any such new generation or energy storage facility or
facilities through its rates for generation and distribution services and does
not petition and receive approval from the Commission for recovery of such
costs through a rate adjustment clause described in clause (ii), the Commission
shall, upon the request of the utility in a
triennial review proceeding, provide for a customer credit
reinvestment offset, as applicable, pursuant to subdivision 8 d with respect to
all costs deemed reasonable and prudent by the Commission in a proceeding
pursuant to subsection D of §56-580 or in a
triennial review proceeding.
Electric distribution grid transformation projects are in the
public interest. To the extent that a utility elects to recover the costs of
such electric distribution grid transformation projects through its rates for
generation and distribution services, and does not petition and receive
approval from the Commission for recovery of such costs through a rate
adjustment clause described in clause (vi), the Commission shall, upon the
request of the utility in a triennial
review proceeding, provide for a customer credit reinvestment offset, as
applicable, pursuant to subdivision 8 d with respect to all costs deemed
reasonable and prudent by the Commission in a proceeding for approval of a plan
for electric distribution grid transformation projects pursuant to subdivision
6 or in a triennial
review proceeding.
Neither generation facilities described in clause (ii) that utilize simple-cycle combustion turbines nor new underground facilities shall receive an enhanced rate of return on common equity as described herein, but instead shall receive the utility's general rate of return during the construction phase of the facility and, thereafter, for the entire service life of the facility. No rate adjustment clause for new underground facilities shall allocate costs to, or provide for the recovery of costs from, customers that are served within the large power service rate class for a Phase I Utility and the large general service rate classes for a Phase II Utility. New underground facilities are hereby declared to be ordinary extensions or improvements in the usual course of business under the provisions of §56-265.2.
As used in this subdivision, a generation facility is (1) "coalbed methane gas powered" if the facility is fired at least 50 percent by coalbed methane gas, as such term is defined in §45.2-1600, produced from wells located in the Commonwealth, and (2) "landfill gas powered" if the facility is fired by methane or other combustible gas produced by the anaerobic digestion or decomposition of biodegradable materials in a solid waste management facility licensed by the Waste Management Board. A landfill gas powered facility includes, in addition to the generation facility itself, the equipment used in collecting, drying, treating, and compressing the landfill gas and in transmitting the landfill gas from the solid waste management facility where it is collected to the generation facility where it is combusted.
For purposes of this subdivision, "general rate of return" means the fair combined rate of return on common equity as it is determined by the Commission for such utility pursuant to subdivision 2.
Notwithstanding any other provision of this subdivision, if the Commission finds during the triennial review conducted for a Phase II Utility in 2021 that such utility has not filed applications for all necessary federal and state regulatory approvals to construct one or more nuclear-powered or coal-fueled generation facilities that would add a total capacity of at least 1500 megawatts to the amount of the utility's generating resources as such resources existed on July 1, 2007, or that, if all such approvals have been received, that the utility has not made reasonable and good faith efforts to construct one or more such facilities that will provide such additional total capacity within a reasonable time after obtaining such approvals, then the Commission, if it finds it in the public interest, may reduce on a prospective basis any enhanced rate of return on common equity previously applied to any such facility to no less than the general rate of return for such utility and may apply no less than the utility's general rate of return to any such facility for which the utility seeks approval in the future under this subdivision.
Notwithstanding any other provision of this subdivision, if a Phase II utility obtains approval from the Commission of a rate adjustment clause pursuant to subdivision 6 associated with a test or demonstration project involving a generation facility utilizing energy from offshore wind, and such utility has not, as of July 1, 2023, commenced construction as defined for federal income tax purposes of an offshore wind generation facility or facilities with a minimum aggregate capacity of 250 megawatts, then the Commission, if it finds it in the public interest, may direct that the costs associated with any such rate adjustment clause involving said test or demonstration project shall thereafter no longer be recovered through a rate adjustment clause pursuant to subdivision 6 and shall instead be recovered through the utility's rates for generation and distribution services, with no change in such rates for generation and distribution services as a result of the combination of such costs with the other costs, revenues, and investments included in the utility's rates for generation and distribution services. Any such costs shall remain combined with the utility's other costs, revenues, and investments included in its rates for generation and distribution services until such costs are fully recovered.
7. Any petition filed pursuant to subdivision 4, 5, or 6 shall
be considered by the Commission on a stand-alone basis without regard to the
other costs, revenues, investments, or earnings of the utility. Any costs
incurred by a utility prior to the filing of such petition, or during the
consideration thereof by the Commission, that are proposed for recovery in such
petition and that are related to subdivision 5 a, or that are related to
facilities and projects described in clause (i) of subdivision 6, or that are
related to new underground facilities described in clause (iv) of subdivision
6, shall be deferred on the books and records of the utility until the
Commission's final order in the matter, or until the implementation of any
applicable approved rate adjustment clauses, whichever is later. Except as
otherwise provided in subdivision 6, any costs prudently incurred on or after
July 1, 2007, by a utility prior to the filing of such petition, or during the
consideration thereof by the Commission, that are proposed for recovery in such
petition and that are related to facilities and projects described in clause
(ii) or clause (iii) of subdivision 6 that utilize nuclear power, or
coal-fueled facilities and projects described in clause (ii) of subdivision 6
if such coal-fueled facilities will be built by a Phase I Utility, shall be
deferred on the books and records of the utility until the Commission's final
order in the matter, or until the implementation of any applicable approved
rate adjustment clauses, whichever is later. Any costs prudently incurred after
the expiration or termination of capped rates related to other matters
described in subdivision 4, 5, or 6 shall be deferred beginning only upon the
expiration or termination of capped rates, provided, however, that no provision
of this act shall affect the rights of any parties with respect to the rulings
of the Federal Energy Regulatory Commission in PJM Interconnection LLC and
Virginia Electric and Power Company, 109 F.E.R.C. P 61,012 (2004). A utility
shall establish a regulatory asset for regulatory accounting and ratemaking
purposes under which it shall defer its operation and maintenance costs
incurred in connection with (i) the refueling of any nuclear-powered generating
plant and (ii) other work at such plant normally performed during a refueling
outage. The utility shall amortize such deferred costs over the refueling
cycle, but in no case more than 18 months, beginning with the month in which
such plant resumes operation after such refueling. The refueling cycle shall be
the applicable period of time between planned refueling outages for such plant.
As of January 1, 2014, such amortized costs are a component of base rates,
recoverable in base rates only ratably over the refueling cycle rather than
when such outages occur, and are the only nuclear refueling costs recoverable
in base rates. This provision shall apply to any nuclear-powered generating
plant refueling outage commencing after December 31, 2013, and the Commission
shall treat the deferred and amortized costs of such regulatory asset as part
of the utility's costs for the purpose of proceedings conducted (a) with
respect to triennial
filings under subdivision 3 made on and after July 1, 2014, and (b) pursuant to
§56-245 or the Commission's rules governing utility rate increase applications
as provided in subsection B. This provision shall not be deemed to change or
reset base rates.
The Commission's final order regarding any petition filed pursuant to subdivision 4, 5, or 6 shall be entered not more than three months, eight months, and nine months, respectively, after the date of filing of such petition. If such petition is approved, the order shall direct that the applicable rate adjustment clause be applied to customers' bills not more than 60 days after the date of the order, or upon the expiration or termination of capped rates, whichever is later. At any time, the Commission may, in its discretion, upon petition by a Phase I or II Utility or upon its own initiated proceeding, direct the consolidation of any rate adjustment clauses previously implemented pursuant to subdivision 5 or 6 in the interest of judicial economy, customer transparency, or other factors the Commission determines to be appropriate. Any rate adjustment clauses so consolidated shall continue to be considered by the Commission without regard to the other cost, revenues, investments, or earning of the utility pursuant to this subdivision and subdivisions 5 and 6, but will be combined for cost recovery and review purposes.
8. In any triennial
review proceeding, for the purposes of reviewing earnings on the utility's
rates for generation and distribution services, the following utility
generation and distribution costs not proposed for recovery under any other
subdivision of this subsection, as recorded per books by the utility for
financial reporting purposes and accrued against income, shall be attributed to
the test periods under review and deemed fully recovered in the period
recorded: costs associated with asset impairments related to early retirement
determinations made by the utility for utility generation facilities fueled by
coal, natural gas, or oil or for automated meter reading electric distribution
service meters; costs associated with projects necessary to comply with state
or federal environmental laws, regulations, or judicial or administrative
orders relating to coal combustion by-product management that the utility does
not petition to recover through a rate adjustment clause pursuant to
subdivision 5 e; costs associated with severe weather events; and costs
associated with natural disasters. Such costs shall be deemed to have been
recovered from customers through rates for generation and distribution services
in effect during the test periods under review unless such costs, individually
or in the aggregate, together with the utility's other costs, revenues, and
investments to be recovered through rates for generation and distribution
services, result in the utility's earned return on its generation and
distribution services for the combined test periods under review to fall more
than 50 basis points below the fair combined rate of return authorized under
subdivision 2 for such periods or, for any test period commencing after
December 31, 2012, for a Phase II Utility and after December 31, 2013, for a
Phase I Utility, to fall more than 70 basis points below the fair combined rate
of return authorized under subdivision 2 for such periods. In such cases, the
Commission shall, in such triennial
review proceeding, authorize deferred recovery of such costs and allow the
utility to amortize and recover such deferred costs over future periods as
determined by the Commission. The aggregate amount of such deferred costs shall
not exceed an amount that would, together with the utility's other costs,
revenues, and investments to be recovered through rates for generation and
distribution services, cause the utility's earned return on its generation and
distribution services to exceed the fair rate of return authorized under
subdivision 2, less 50 basis points, for the combined test periods under review
or, for any test period commencing after December 31, 2012, for a Phase II
Utility and after December 31, 2013, for a Phase I Utility, to exceed the fair
rate of return authorized under subdivision 2 less 70 basis points. Nothing in
this section shall limit the Commission's authority, pursuant to the provisions
of Chapter 10 (§56-232 et seq.), including specifically §56-235.2, following
the review of combined test period earnings of the utility in a triennial review, for
normalization of nonrecurring test period costs and annualized adjustments for
future costs, in determining any appropriate increase or decrease in the
utility's rates for generation and distribution services pursuant to subdivision
8 a or 8 c.
If the Commission determines,
for subdivisions a, b, and c as a result of such
any triennial review initiated prior to
July 1, 2023, or,
for subdivision d,
as a result of any triennial or biennial review initiated prior
to January 1, 2024,
that:
a. Revenue reductions related to energy efficiency measures or
programs approved and deployed since the utility's previous triennial review have caused the utility, as verified by
the Commission, during the test period or periods under review, considered as a
whole, to earn more than 50 basis points below a fair combined rate of return
on its generation and distribution services or, for any test period commencing
after December 31, 2012, for a Phase II Utility and after December 31, 2013,
for a Phase I Utility, more than 70 basis points below a fair combined rate of
return on its generation and distribution services, as determined in
subdivision 2, without regard to any return on common equity or other matters
determined with respect to facilities described in subdivision 6, the
Commission shall order increases to the utility's rates for generation and
distribution services necessary to recover such revenue reductions. If the
Commission finds, for reasons other than revenue reductions related to energy efficiency
measures, that the utility has, during the test period or periods under review,
considered as a whole, earned more than 50 basis points below a fair combined
rate of return on its generation and distribution services or, for any test
period commencing after December 31, 2012, for a Phase II Utility and after
December 31, 2013, for a Phase I Utility, more than 70 basis points below a
fair combined rate of return on its generation and distribution services, as
determined in subdivision 2, without regard to any return on common equity or
other matters determined with respect to facilities described in subdivision 6,
the Commission shall order increases to the utility's rates necessary to
provide the opportunity to fully recover the costs of providing the utility's
services and to earn not less than such fair combined rate of return, using the
most recently ended 12-month test period as the basis for determining the
amount of the rate increase necessary. However, in the first triennial review proceeding conducted after January 1,
2021, for a Phase II Utility, the Commission may not order a rate increase, and
in all triennial reviews of a Phase I or Phase II
utility, the Commission may not order such rate increase unless it finds that
the resulting rates are necessary to provide the utility with the opportunity
to fully recover its costs of providing its services and to earn not less than
a fair combined rate of return on both its generation and distribution
services, as determined in subdivision 2, without regard to any return on
common equity or other matters determined with respect to facilities described
in subdivision 6, using the most recently ended 12-month test period as the
basis for determining the permissibility of any rate increase under the standards
of this sentence, and the amount thereof; and provided that, solely in
connection with making its determination concerning the necessity for such a
rate increase or the amount thereof, the Commission shall, in any triennial
biennial review proceeding conducted prior to July 1, 2028,
exclude from this most recently ended 12-month test period any remaining
investment levels associated with a prior customer credit reinvestment offset
pursuant to subdivision d.
b. The utility has, during the test period or test periods under review, considered as a whole, earned more than 50 basis points above a fair combined rate of return on its generation and distribution services or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, more than 70 basis points above a fair combined rate of return on its generation and distribution services, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, the Commission shall, subject to the provisions of subdivisions 8 d and 9, direct that 60 percent of the amount of such earnings that were more than 50 basis points, or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, that 70 percent of the amount of such earnings that were more than 70 basis points, above such fair combined rate of return for the test period or periods under review, considered as a whole, shall be credited to customers' bills. Any such credits shall be amortized over a period of six to 12 months, as determined at the discretion of the Commission, following the effective date of the Commission's order, and shall be allocated among customer classes such that the relationship between the specific customer class rates of return to the overall target rate of return will have the same relationship as the last approved allocation of revenues used to design base rates; or
c. In any
triennial review proceeding conducted after January 1, 2020,
for a Phase I Utility or after January 1, 2021, for a Phase II Utility in which
the The
utility has, during the test period or test periods under review, considered as
a whole, earned more than 50 basis points above a fair combined rate of return
on its generation and distribution services or, for any test period commencing
after December 31, 2012, for a Phase II Utility and after December 31, 2013,
for a Phase I Utility, more than 70 basis points above a fair combined rate of
return on its generation and distribution services, as determined in
subdivision 2, without regard to any return on common equity or other matter
determined with respect to facilities described in subdivision 6, and the
combined aggregate level of capital investment that the Commission has approved
other than those capital investments that the Commission has approved for
recovery pursuant to a rate adjustment clause pursuant to subdivision 6 made by
the utility during the test periods under review in that
triennial review proceeding in new utility-owned generation facilities
utilizing energy derived from sunlight, or from wind, and in electric
distribution grid transformation projects, as determined pursuant to
subdivision 8 d, does not equal or exceed 100 percent of the earnings that are
more than 70 basis points above the utility's fair combined rate of return on
its generation and distribution services for the combined test periods under
review in that triennial review proceeding, the
Commission shall, subject to the provisions of subdivision 9 and in addition to
the actions authorized in subdivision b, also order reductions to the utility's
rates it finds appropriate. However, in the first
triennial review proceeding conducted after January 1, 2021, for a Phase
II Utility, any reduction to the utility's rates ordered by the Commission
pursuant to this subdivision shall not exceed $50 million in annual revenues, with
any reduction allocated to the utility's rates for generation services, and in
each triennial review of a Phase I or Phase II
Utility, the Commission may not order such rate reduction unless it finds that
the resulting rates will provide the utility with the opportunity to fully
recover its costs of providing its services and to earn not less than a fair
combined rate of return on its generation and distribution services, as
determined in subdivision 2, without regard to any return on common equity or other
matters determined with respect to facilities described in subdivision 6, using
the most recently ended 12-month test period as the basis for determining the
permissibility of any rate reduction under the standards of this sentence, and
the amount thereof; and
d. (Expires July 1, 2028) In any
triennial review proceeding conducted after December 31,
2017, upon the request of the utility, the Commission shall determine, prior to
directing that 70 percent of earnings that are more than 70 basis points above
the utility's fair combined rate of return on its generation and distribution
services for the test period or periods under review be credited to customer
bills pursuant to subdivision 8 b, the aggregate level of prior capital
investment that the Commission has approved other than those capital
investments that the Commission has approved for recovery pursuant to a rate
adjustment clause pursuant to subdivision 6 made by the utility during the test
period or periods under review in both (i) new utility-owned generation
facilities utilizing energy derived from sunlight, or from onshore or offshore
wind, and (ii) electric distribution grid transformation projects, as
determined by the utility's plant in service and construction work in progress
balances related to such investments as recorded per books by the utility for
financial reporting purposes as of the end of the most recent test period under
review. Any such combined capital investment amounts shall offset any customer
bill credit amounts, on a dollar for dollar basis, up to the aggregate level of
invested or committed capital under clauses (i) and (ii). The aggregate level
of qualifying invested or committed capital under clauses (i) and (ii) is
referred to in this subdivision as the customer credit reinvestment offset,
which offsets the customer bill credit amount that the utility has invested or
will invest in new solar or wind generation facilities or electric distribution
grid transformation projects for the benefit of customers, in amounts up to 100
percent of earnings that are more than 70 basis points above the utility's fair
rate of return on its generation and distribution services, and thereby reduce
or eliminate otherwise incremental rate adjustment clause charges and increases
to customer bills, which is deemed to be in the public interest. If 100 percent
of the amount of earnings that are more than 70 basis points above the
utility's fair combined rate of return on its generation and distribution
services, as determined in subdivision 2, exceeds the aggregate level of
invested capital in new utility-owned generation facilities utilizing energy
derived from sunlight, or from wind, and electric distribution grid
transformation projects, as provided in clauses (i) and (ii), during the test period
or periods under review, then 70 percent of the amount of such excess shall be
credited to customer bills as provided in subdivision 8 b in connection with
the triennial review proceeding.
The portion of any costs associated with new utility-owned generation
facilities utilizing energy derived from sunlight, or from wind, or electric
distribution grid transformation projects that is the subject of any customer
credit reinvestment offset pursuant to this subdivision shall not thereafter be
recovered through the utility's rates for generation and distribution services
over the service life of such facilities and shall not thereafter be included
in the utility's costs, revenues, and investments in future
triennial review proceedings conducted pursuant to subdivision
2 and shall not be the subject of a rate adjustment clause petition pursuant to
subdivision 6. The portion of any costs associated with new utility-owned
generation facilities utilizing energy derived from sunlight, or from wind, or
electric distribution grid transformation projects that is not the subject of
any customer credit reinvestment offset pursuant to this subdivision may be
recovered through the utility's rates for generation and distribution services
over the service life of such facilities and shall be included in the utility's
costs, revenues, and investments in future
triennial review proceedings conducted pursuant to
subdivision 2 until such costs are fully recovered, and if such costs are
recovered through the utility's rates for generation and distribution services,
they shall not be the subject of a rate adjustment clause petition pursuant to
subdivision 6. Only the portion of such costs of new utility-owned generation
facilities utilizing energy derived from sunlight, or from wind, or electric
distribution grid transformation projects that has not been included in any
customer credit reinvestment offset pursuant to this subdivision, and not
otherwise recovered through the utility's rates for generation and distribution
services, may be the subject of a rate adjustment clause petition by the
utility pursuant to subdivision 6.
The Commission's final order regarding such triennial review shall be
entered not more than eight months after the date of filing, and any revisions
in rates or credits so ordered shall take effect not more than 60 days after
the date of the order. The fair combined rate of return on common equity
determined pursuant to subdivision 2 in such
triennial review shall apply, for purposes of reviewing the
utility's earnings on its rates for generation and distribution services, to
the entire two or three, as applicable,
successive 12-month test periods ending December 31 immediately preceding the
year of the utility's subsequent triennial
review filing under subdivision 3 and shall apply to applicable rate adjustment
clauses under subdivisions 5 and 6 prospectively from the date the Commission's
final order in the triennial
review proceeding, utilizing rate adjustment clause true-up protocols as the
Commission in its discretion may determine.
9. In any biennial review:
a. If the Commission determines that the utility has during the test period or test periods under review, considered as a whole, earned more than 70 basis points above a fair combined rate of return on its generation and distribution services previously authorized by the Commission, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, which have not been combined with the utility's costs, revenues, and investments for generation and distribution services, the Commission shall direct that 70 percent of the amount of such earnings that were more than 70 basis points above such fair combined rate of return for the test period or periods under review, considered as a whole, be credited to customers' bills. Any such credits shall be amortized over a period of six to 12 months, as determined at the discretion of the Commission, following the effective date of the Commission's order, and shall be allocated among customer classes such that the relationship between the specific customer class rates of return to the overall target rate of return will have the same relationship as the last approved allocation of revenues used to design base rates.
b. The Commission shall order prospective increases or reductions to the utility's rates for generation or distribution services as it determines, in its discretion, to be appropriate, in order to ensure that the utility's rates for generation and distribution services (i) are just and reasonable and (ii) provide the utility an opportunity to fully recover its costs of providing such services over the rate period ending on December 31 of the year immediately prior to the utility's succeeding biennial review and to earn not less than a fair combined rate of return on its generation and distribution services, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, which have not been combined with the utility's costs, revenues, and investments for generation and distribution services, using the most recently ended 12-month test period, along with normalization of nonrecurring test period costs and annualized adjustments for future costs as the basis for determining the appropriateness of any rate adjustment. The Commission may, to the extent it finds such action aligns with the utility's projected cost of service, direct that any such increase or reduction in the utility's rates for generation or distribution services be implemented on a staggered basis at the commencement and mid-point of the succeeding rate period.
10. If, as a result of a triennial review required under this subsection and conducted with respect to any test period or periods under review ending later than December 31, 2010 (or, if the Commission has elected to stagger its biennial reviews of utilities as provided in subdivision 1, under review ending later than December 31, 2010, for a Phase I Utility, or December 31, 2011, for a Phase II Utility), the Commission finds, with respect to such test period or periods considered as a whole, that (i) any utility has, during the test period or periods under review, considered as a whole, earned more than 50 basis points above a fair combined rate of return on its generation and distribution services or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, more than 70 basis points above a fair combined rate of return on its generation and distribution services, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, and (ii) the total aggregate regulated rates of such utility at the end of the most recently ended 12-month test period exceeded the annual increases in the United States Average Consumer Price Index for all items, all urban consumers (CPI-U), as published by the Bureau of Labor Statistics of the United States Department of Labor, compounded annually, when compared to the total aggregate regulated rates of such utility as determined pursuant to the review conducted for the base period, the Commission shall, unless it finds that such action is not in the public interest or that the provisions of subdivisions 8 b and c are more consistent with the public interest, direct that any or all earnings for such test period or periods under review, considered as a whole that were more than 50 basis points, or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, more than 70 basis points, above such fair combined rate of return shall be credited to customers' bills, in lieu of the provisions of subdivisions 8 b and c, provided that no credits shall be provided pursuant to this subdivision in connection with any triennial review unless such bill credits would be payable pursuant to the provisions of subdivision 8 d, and any credits under this subdivision shall be calculated net of any customer credit reinvestment offset amounts under subdivision 8 d. Any such credits shall be amortized and allocated among customer classes in the manner provided by subdivision 8 b. For purposes of this subdivision:
"Base period" means (i) the test period ending December 31, 2010 (or, if the Commission has elected to stagger its biennial reviews of utilities as provided in subdivision 1, the test period ending December 31, 2010, for a Phase I Utility, or December 31, 2011, for a Phase II Utility), or (ii) the most recent test period with respect to which credits have been applied to customers' bills under the provisions of this subdivision, whichever is later.
"Total aggregate regulated rates" shall include: (i) fuel tariffs approved pursuant to §56-249.6, except for any increases in fuel tariffs deferred by the Commission for recovery in periods after December 31, 2010, pursuant to the provisions of clause (ii) of subsection C of §56-249.6; (ii) rate adjustment clauses implemented pursuant to subdivision 4 or 5; (iii) revisions to the utility's rates pursuant to subdivision 8 a; (iv) revisions to the utility's rates pursuant to the Commission's rules governing utility rate increase applications, as permitted by subsection B, occurring after July 1, 2009; and (v) base rates in effect as of July 1, 2009.
10. 11. For purposes of this
section, the Commission shall regulate the rates, terms and conditions of any
utility subject to this section on a stand-alone basis utilizing the actual
end-of-test period capital structure and cost of capital of such utility,
excluding any debt associated with securitized bonds that are the obligation of
non-Virginia jurisdictional customers, unless the Commission finds that the
debt to equity ratio of such capital structure is unreasonable for such
utility, in which case the Commission may utilize a debt to equity ratio that
it finds to be reasonable for such utility in determining any rate adjustment
pursuant to subdivisions 8 a and c, and without regard to the cost of capital,
capital structure, revenues, expenses or investments of any other entity with
which such utility may be affiliated. In particular, and without limitation,
the Commission shall determine the federal and state income tax costs for any
such utility that is part of a publicly traded, consolidated group as follows:
(i) such utility's apportioned state income tax costs shall be calculated
according to the applicable statutory rate, as if the utility had not filed a
consolidated return with its affiliates, and (ii) such utility's federal income
tax costs shall be calculated according to the applicable federal income tax
rate and shall exclude any consolidated tax liability or benefit adjustments
originating from any taxable income or loss of its affiliates.
Throughout the duration of the construction period for any project constructed by a Phase II Utility pursuant to §56-585.1:11, such utility shall maintain, subject to audit by the Commission, its common equity capitalization to total capitalization ratio at a level at least equal to the average of such ratio for all utilities in the applicable Phase II Utility's peer group investor-owned utilities, as determined according to subdivision A 2 b, and as authorized by such utilities' regulatory commission in their most recent governing rate proceeding.
B. Nothing in this section shall preclude an investor-owned incumbent electric utility from applying for an increase in rates pursuant to § 56-245 or the Commission's rules governing utility rate increase applications; however, in any such filing, a fair rate of return on common equity shall be determined pursuant to subdivision A 2. Nothing in this section shall preclude such utility's recovery of fuel and purchased power costs as provided in § 56-249.6.
C. Except as otherwise provided in this section, the Commission shall exercise authority over the rates, terms and conditions of investor-owned incumbent electric utilities for the provision of generation, transmission and distribution services to retail customers in the Commonwealth pursuant to the provisions of Chapter 10 (§56-232 et seq.), including specifically §56-235.2.
D. The Commission may determine, during any proceeding authorized or required by this section, the reasonableness or prudence of any cost incurred or projected to be incurred, by a utility in connection with the subject of the proceeding. A determination of the Commission regarding the reasonableness or prudence of any such cost shall be consistent with the Commission's authority to determine the reasonableness or prudence of costs in proceedings pursuant to the provisions of Chapter 10 (§56-232 et seq.). In determining the reasonableness or prudence of a utility providing energy and capacity to its customers from renewable energy resources, the Commission shall consider the extent to which such renewable energy resources, whether utility-owned or by contract, further the objectives of the Commonwealth Clean Energy Policy set forth in §45.2-1706.1, and shall also consider whether the costs of such resources is likely to result in unreasonable increases in rates paid by customers.
E. Notwithstanding any other provision of law, the Commission shall determine the amortization period for recovery of any appropriate costs due to the early retirement of any electric generation facilities owned or operated by any Phase I Utility or Phase II Utility. In making such determination, the Commission shall (i) perform an independent analysis of the remaining undepreciated capital costs; (ii) establish a recovery period that best serves ratepayers; and (iii) allow for the recovery of any carrying costs that the Commission deems appropriate.
F. Except for early retirement determinations identified by the utility in an integrated resource plan filed with the Commission pursuant to §56-599 by July 1, 2023, an investor-owned incumbent electric utility shall not permanently retire an electric power generation facility from service after July 1, 2023, without first obtaining the approval of the Commission, upon petition from such investor-owned incumbent electric utility, and a finding by the Commission that the retirement determination, after consideration of the impact of the proposed retirement on reliability or security of electric service to customers, is reasonable and prudent. The Commission shall include in its report required by subsection B of §56-596 any information concerning the impacts of generation unit retirement determinations by a Phase I or Phase II Utility, utilizing information from the respective utility's integrated resource plan.
G. The Commission shall promulgate such rules and regulations as may be necessary to implement the provisions of this section.
§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.
"Low-income community" means a census tract within the Commonwealth designated by the U.S. Department of Housing and Urban Development in 2019 or any year thereafter as a qualified census tract for purposes of the Low-Income Housing Tax Credit pursuant to §42 of the Internal Revenue Code.
"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 (i) 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, or (ii) is located in a low-income community as provided in subdivision 15.
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 and ensure that the selection of such facilities complies with the requirements of subdivision 15 regarding the location of eligible generating facilities in low-income communities.
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 as provided in subsection G F.
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.
15. Notwithstanding any provision of this section to the contrary, effective July 1, 2020, an investor-owned utility shall not select an eligible generating facility that is located outside a low-income community for dedication to its pilot program unless the investor-owned utility contemporaneously selects for dedication to its pilot program one or more eligible generating facilities that are located within a low-income community and of which the pilot program costs equal or exceed the pilot program costs of the eligible generating facility that is located outside a low-income community.
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 Committee on Labor and Commerce and the Senate
Committee on Commerce and Labor. 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
Committee on Labor and Commerce and the Senate Committee on Commerce and Labor
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. F. At any
time after filing its report on the status of its pilot program as required by
subsection F E,
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.
§56-585.1:4. Development of solar and wind generation and energy storage capacity in the Commonwealth.
A. Prior to January 1, 2024, (i) the construction or purchase by a public utility of one or more solar or wind generation facilities located in the Commonwealth or off the Commonwealth's Atlantic shoreline, each having a rated capacity of at least one megawatt and having in the aggregate a rated capacity that does not exceed 5,000 megawatts, or (ii) the purchase by a public utility of energy, capacity, and environmental attributes from solar facilities described in clause (i) owned by persons other than a public utility is in the public interest, and the Commission shall so find if required to make a finding regarding whether such construction or purchase is in the public interest.
B. Prior to January 1, 2024, (i) the construction or purchase by a public utility of one or more solar or wind generation facilities located in the Commonwealth or off the Commonwealth's Atlantic shoreline, each having a rated capacity of less than one megawatt, including rooftop solar installations with a capacity of not less than 50 kilowatts, and having in the aggregate a rated capacity that does not exceed 500 megawatts, or (ii) the purchase by a public utility of energy, capacity, and environmental attributes from solar facilities described in clause (i) owned by persons other than a public utility is in the public interest, and the Commission shall so find if required to make a finding regarding whether such construction or purchase is in the public interest.
C. The aggregate cap of 5,000 megawatts of rated capacity described in clause (i) of subsection A, the aggregate cap of 500 megawatts of rated capacity described in clause (i) of subsection B, and the aggregate cap of 200 megawatts of rated capacity described in subsection I are separate and independent from each other. The capacity of facilities in subsection B shall not be counted in determining the capacity of facilities in subsection A or I; the capacity of facilities in subsection A shall not be counted in determining the capacity of facilities in subsection B or I; and the capacity of facilities in subsection I shall not be counted in determining the capacity of facilities in subsection A or B.
D. Twenty-five percent of the solar generation capacity placed in service on or after July 1, 2018, located in the Commonwealth, and found to be in the public interest pursuant to subsection A or B shall be from the purchase by a public utility of energy, capacity, and environmental attributes from solar facilities owned by persons other than a public utility. The remainder shall be construction or purchase by a public utility of one or more solar generation facilities located in the Commonwealth. All of the solar generation capacity located in the Commonwealth and found to be in the public interest pursuant to subsection A or B shall be subject to competitive procurement, provided that a public utility may select solar generation capacity without regard to whether such selection satisfies price criteria if the selection of the solar generating capacity materially advances non-price criteria, including favoring geographic distribution of generating capacity, areas of higher employment, or regional economic development, if such non-price solar generating capacity selected does not exceed 25 percent of the utility's solar generating capacity.
E. Construction, purchasing, or leasing activities for a test or demonstration project for a new utility-owned and utility-operated generating facility or facilities utilizing energy derived from offshore wind with an aggregate capacity of not more than 16 megawatts are in the public interest.
F. Prior to January 1, 2035, (i) the construction by a public utility of one or more energy storage facilities located in the Commonwealth, having in the aggregate a rated capacity that does not exceed 2,700 megawatts, or (ii) the purchase by a public utility of energy storage facilities described in clause (i) owned by persons other than a public utility or the capacity from such facilities is in the public interest, and the Commission shall so find if required to make a finding regarding whether such construction or purchase is in the public interest.
G. At least 35 percent of the energy storage capacity placed in service on or after July 1, 2020, located in the Commonwealth and found to be in the public interest pursuant to subsection F shall be from the purchase by a public utility of energy storage facilities owned by persons other than a public utility or the capacity from such facilities. All of the energy storage facilities located in the Commonwealth and found to be in the public interest pursuant to subsection F shall be subject to competitive procurement, provided that a public utility may select energy storage facilities without regard to whether such selection satisfies price criteria if the selection of the energy storage facilities materially advances non-price criteria, including favoring geographic distribution of generating facilities, areas of higher employment, or regional economic development, if such energy storage facilities selected for the advancement of non-price criteria do not exceed 25 percent of the utility's energy storage capacity.
H. A utility may elect to petition the Commission, outside of
a triennial
biennial review proceeding conducted pursuant to §
56-585.1, at any time for a prudency determination with respect to the
construction or purchase by the utility of one or more solar or wind generation
facilities located in the Commonwealth or off the Commonwealth's Atlantic
Shoreline or the purchase by the utility of energy, capacity, and environmental
attributes from solar or wind facilities owned by persons other than the
utility. The Commission's final order regarding any such petition shall be
entered by the Commission not more than three months after the date of the filing
of such petition.
I. Prior to January 1, 2024, (i) the construction or purchase by a public utility of one or more solar or wind generation facilities located on a previously developed project site in the Commonwealth having in the aggregate a rated capacity that does not exceed 200 megawatts or (ii) the purchase by a public utility of energy, capacity, and environmental attributes from solar facilities described in clause (i) owned by persons other than a public utility, is in the public interest.
§56-599. Integrated resource plan required.
A. Each electric utility shall file an updated integrated
resource plan by July 1, 2015. Thereafter, each electric utility shall file an
updated integrated resource plan by May 1, in each year immediately preceding the
year the utility is subject to a triennial biennial review filing. A copy
of each integrated resource plan shall be provided to the Chairman of the House
Committee on Labor and Commerce, the Chairman of the Senate Committee on
Commerce and Labor, and to the Chairman of the Commission on Electric Utility
Regulation. All updated integrated resource plans shall comply with the
provisions of any relevant order of the Commission establishing guidelines for
the format and contents of updated and revised integrated resource plans. Each
integrated resource plan shall consider options for maintaining and enhancing
rate stability, energy independence, economic development including retention
and expansion of energy-intensive industries, and service reliability.
B. In preparing an integrated resource plan, each electric utility shall systematically evaluate and may propose:
1. Entering into short-term and long-term electric power purchase contracts;
2. Owning and operating electric power generation facilities;
3. Building new generation facilities;
4. Relying on purchases from the short term or spot markets;
5. Making investments in demand-side resources, including energy efficiency and demand-side management services;
6. Taking such other actions, as the Commission may approve, to diversify its generation supply portfolio and ensure that the electric utility is able to implement an approved plan;
7. The methods by which the electric utility proposes to acquire the supply and demand resources identified in its proposed integrated resource plan;
8. The effect of current and pending state and federal environmental regulations upon the continued operation of existing electric generation facilities or options for construction of new electric generation facilities;
9. The most cost effective means of complying with current and pending state and federal environmental regulations, including compliance options to minimize effects on customer rates of such regulations;
10. Long-term electric distribution grid planning and proposed electric distribution grid transformation projects;
11. Developing a long-term plan for energy efficiency measures to accomplish policy goals of reduction in customer bills, particularly for low-income, elderly, and disabled customers; reduction in emissions; and reduction in carbon intensity; and
12. Developing a long-term plan to integrate new energy storage facilities into existing generation and distribution assets to assist with grid transformation.
C. As part of preparing any integrated resource plan pursuant to this section, each utility shall conduct a facility retirement study for owned facilities located in the Commonwealth that emit carbon dioxide as a byproduct of combusting fuel and shall include the study results in its integrated resource plan. Upon filing the integrated resource plan with the Commission, the utility shall contemporaneously disclose the study results to each planning district commission, county board of supervisors, and city and town council where such electric generation unit is located, the Department of Energy, the Department of Housing and Community Development, the Virginia Employment Commission, and the Virginia Council on Environmental Justice. The disclosure shall include (i) the driving factors of the decision to retire and (ii) the anticipated retirement year of any electric generation unit included in the plan. Any electric generating facility with an anticipated retirement date that meets the criteria of §45.2-1701.1 shall comply with the public disclosure requirements therein.
D. The Commission shall analyze and review an integrated resource plan and, after giving notice and opportunity to be heard, the Commission shall make a determination within nine months after the date of filing as to whether such an integrated resource plan is reasonable and is in the public interest.
