10100484D
SENATE BILL NO. 74
Offered January 13, 2010
Prefiled January 5, 2010
A BILL to amend and reenact §§56-234.2, 56-235.2, 56-249.6,
56-577, 56-585.1, and 56-585.2 of the Code of Virginia, relating to the regulation
of electric utilities.
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Patrons-- Reynolds and Puckett; Delegates: Armstrong and Crockett-Stark
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Referred to Committee on Commerce and Labor
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Be it enacted by the General Assembly of Virginia:
1. That §§56-234.2, 56-235.2, 56-249.6, 56-577, 56-585.1,
and 56-585.2 of the Code of Virginia are amended and reenacted as follows:
§56-234.2. Review of rates.
The Commission shall review the rates of any public utility on
an annual basis when, in the opinion of the Commission, such annual review is
in the public interest, provided that the rates of a public utility subject to
§56-585.1 shall be reviewed in accordance with subsection A of that section.
§56-235.2. All rates, tolls, etc., to be just and reasonable
to jurisdictional customers; findings and conclusions to be set forth;
alternative forms of regulation for electric companies.
A. Any rate, toll, charge or schedule of any public utility
operating in this Commonwealth shall be considered to be just and reasonable
only if: (1) the public utility has demonstrated that such rates, tolls,
charges or schedules in the aggregate provide revenues not in excess of the
aggregate actual costs incurred by the public utility in serving customers
within the jurisdiction of the Commission, including subject to
such normalization for nonrecurring costs and annualized adjustments for known future increases in costs as the Commission finds reasonably can be predicted to occur during
the rate year may deem reasonable,
and a fair return on the public utility's rate base used to serve those
jurisdictional customers, which return shall
be calculated in accordance with §56-585.1 for utilities subject to such
section; (1a) the investor-owned public electric utility
has demonstrated that no part of such rates, tolls, charges or schedules
includes costs for advertisement, except for advertisements either required by
law or rule or regulation, or for advertisements which solely promote the
public interest, conservation or more efficient use of energy; and (2) the
public utility has demonstrated that such rates, tolls, charges or schedules
contain reasonable classifications of customers. Notwithstanding §56-234, the
Commission may approve, either in the context of or apart from a rate
proceeding after notice to all affected parties and hearing, special rates,
contracts or incentives to individual customers or classes of customers where it
finds such measures are in the public interest. Such special charges shall not
be limited by the provisions of §56-235.4. In determining costs of service,
the Commission may use the test year method of estimating revenue needs, but shall not consider
any adjustments or expenses that are speculative or cannot be predicted with
reasonable certainty. In any Commission order establishing
a fair and reasonable rate of return for an investor-owned gas, telephone or
electric public utility, the Commission shall set forth the findings of fact
and conclusions of law upon which such order is based.
For ratemaking purposes, the Commission shall determine the
federal and state income tax costs for investor-owned water, gas, or electric
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.
B. The Commission shall, before approving special rates,
contracts, incentives or other alternative regulatory plans under subsection A,
ensure that such action (i) protects the public interest, (ii) will not
unreasonably prejudice or disadvantage any customer or class of customers, and
(iii) will not jeopardize the continuation of reliable electric service.
C. After notice and public hearing, the Commission shall issue
guidelines for special rates adopted pursuant to subsection A that will ensure
that other customers are not caused to bear increased rates as a result of such
special rates.
§56-249.6. Recovery of fuel and purchased power costs.
A. 1. Each electric utility that purchases fuel for the
generation of electricity or purchases power and that was not, as of July 1,
1999, bound by a rate case settlement adopted by the Commission that extended
in its application beyond January 1, 2002, shall submit to the Commission its
estimate of fuel costs, including the cost of purchased power, for the 12-month
period beginning on the date prescribed by the Commission. Upon investigation
of such estimates and hearings in accordance with law, the Commission shall
direct each company to place in effect tariff provisions designed to recover
the fuel costs determined by the Commission to be appropriate for that period,
adjusted for any over-recovery or under-recovery of fuel costs previously
incurred.
2. The Commission shall continuously review fuel costs and if
it finds that any utility described in subdivision A 1 is in an over-recovery
position by more than five percent, or likely to be so, it may reduce the fuel
cost tariffs to correct the over-recovery.
3. Beginning July 1, 2009, for all utilities described in
subdivision A 1 and subsection B, if the Commission approves any increase in
fuel factor charges pursuant to this section that would increase the total
rates of the residential class of customers of any such utility by more than 20
percent, the Commission, within six months following the effective date of such
increase, shall review fuel costs, and if the Commission finds that the utility
is, or is likely to be, in an over-recovery position with respect to fuel costs
for the 12-month period for which the increase in fuel factor charges was
approved by more than five percent, it may reduce the utility's fuel cost
tariffs to correct the over-recovery.
B. All fuel costs recovery tariff provisions in effect on
January 1, 2004, for any electric utility that purchases fuel for the
generation of electricity and 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, shall remain in effect until the later of (i) July 1,
2007 or (ii) the establishment of tariff provisions under subsection C. Any such
utility shall continue to report to the Commission annually its actual fuel
costs, including the cost of purchased power.
C. Each electric utility described in subsection B shall
submit annually to the Commission its estimate of fuel costs, including the
cost of purchased power, for successive 12-month periods beginning on July 1,
2007, and each July 1 thereafter. Upon investigation of such estimates and
hearings in accordance with law, the Commission shall direct each such utility
to place in effect tariff provisions designed to recover the fuel costs
determined by the Commission to be appropriate for such periods, adjusted for
any over-recovery or under-recovery of fuel costs previously incurred; however,
(i) no such adjustment for any over-recovery or under-recovery of fuel costs
previously incurred shall be made for any period prior to July 1, 2007, and
(ii) the Commission shall order that the deferral portion, if any, of the total
increase in fuel tariffs for all classes as determined by the Commission to be
appropriate for the 12-month period beginning July 1, 2007, above the fuel
tariffs previously existing, shall be deferred without interest and recovered
from all classes of customers as follows: (i) in the 12-month period beginning
July 1, 2008, that part of the deferral portion of the increase in fuel tariffs
that the Commission determines would increase the total rates of the
residential class of customers of the utility by four percent over the level of
such total rates in existence on June 30, 2008, shall be recovered; (ii) in the
12-month period beginning July 1, 2009, that part of the balance of the
deferral portion of the increase in fuel tariffs, if any, that the Commission
determines would increase the total rates of the residential class of customers
of the utility by four percent over the level of such total rates in existence
on June 30, 2009, shall be recovered; and (iii) in the 12-month period
beginning July 1, 2010, the entire balance of the deferral portion of the
increase in fuel tariffs, if any, shall be recovered. The "deferral
portion of the increase in fuel tariffs" means the portion of such
increase in fuel tariffs that exceeds the amount of such increase in fuel
tariffs that the Commission determines would increase the total rates of the
residential class of customers of the utility by more than four percent over
the level of such total rates in existence on June 30, 2007.
D. In proceedings under subsections A and C:
1. Energy revenues associated with off-system sales of power shall
be credited against fuel factor expenses in an
amount equal to the total incremental fuel factor costs incurred in the
production and delivery of such sales such manner and in such amount as the Commission
finds is in the public interest. In
addition, 75 percent such portion of the total annual margins from off-system
sales that the Commission finds is in the public interest
shall be credited against fuel factor expenses; however, the Commission, upon application
and after notice and opportunity for hearing, may require that a smaller
percentage of such margins be so credited if it finds by clear and convincing
evidence that such requirement is in the public interest. The remaining margins
from off-system sales shall not be considered in the biennial reviews of
electric utilities conducted pursuant to §56-585.1. In the event such margins result in a net loss to the
electric utility, (i) no the Commission may
elect, if
doing so is found to be in the public interest, (i)
not to apply such
charges shall be applied to fuel
factor expenses and or (ii) not
to consider any such net losses shall not be considered
in the biennial reviews of electric utilities conducted pursuant to §56-585.1 in rate case proceedings.
For purposes of this subsection, "margins from off-system sales"
shall mean the total revenues received from off-system sales transactions less
the total incremental costs incurred; and
2. The Commission shall disallow recovery of any fuel costs
that it finds without just cause to be the result of failure of the utility to
make every reasonable effort to minimize fuel costs or any decision of the
utility resulting in unreasonable fuel costs, giving due regard to reliability
of service and the need to maintain reliable sources of supply, economical
generation mix, generating experience of comparable facilities, and
minimization of the total cost of providing service.
E. The Commission is authorized to promulgate, in accordance
with the provisions of this section, all rules and regulations necessary to
allow the recovery by electric utilities of all of their prudently incurred
fuel costs under subsections A and C, including the cost of purchased power, as
precisely and promptly as possible, with no over-recovery or under-recovery,
except as provided in subsection C, in a manner that will tend to assure public
confidence and minimize abrupt changes in charges to consumers.
F. The
Commission may, however,
dispense with the procedures
set forth above for
any electric utility if it finds, after notice and hearing, that the electric
utility's fuel costs can be
reasonably recovered through the rates and charges investigated and established
in accordance with other sections of this
chapter.
§56-577. 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. From January 1, 2004, until the expiration or termination
of capped rates, all retail customers of electric energy within the
Commonwealth, regardless of customer class, shall be permitted to purchase
electric energy from any supplier of electric energy licensed to sell retail
electric energy within the Commonwealth. After the expiration or termination of
capped rates, and subject to the provisions of subdivisions 4 and 5, 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. If such customer does not purchase electric energy from
licensed suppliers after that date, such customer shall purchase electric
energy from its incumbent electric utility.
b. Except as provided in subdivision 4, the demands of
individual retail customers may 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. 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, 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. The costs of serving a customer that has received an
exemption from the five-year notice requirement under subdivision 3 c hereof
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 by the Commission
pursuant to either subsection A or B of §
56-585.1, as applicable. 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. After the expiration or termination of capped rates, 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. After the expiration or termination of capped rates,
individual retail customers of electric energy within the Commonwealth,
regardless of customer class, shall be permitted 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, except for any
incumbent electric utility other than 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.
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.
§56-585.1. Generation, distribution, and transmission rates.
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.) of this title, 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 In
selecting such majority of peer group investor-owned electric utilities, the
Commission shall first remove from such group the two utilities within such
group that have the lowest reported returns of the group, as well as the two
utilities within such group that have the highest reported 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 biennial
review, the Commission shall identify the utilities in such peer group it
selected for the calculation of such limitation. For purposes of this subsection, 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 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 biennial review; and
(iv) it is not an affiliate of the utility subject to such biennial review.
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 in a proceeding
pursuant to subsection B. 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 a)
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 b)
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 biennial reviews of the rates, terms and conditions for the
provision of generation, distribution and transmission services by each
investor-owned incumbent electric utility, 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 rate
proceeding conducted pursuant to subsection B. In
addition to other considerations, in setting the return on equity within the
range allowed by this subsection, 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. Proceedings conducted pursuant to this subsection
shall be 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. The first such review
shall utilize the two successive 12-month test periods ending December 31,
2010. However, the Commission may, in its discretion, elect to stagger its
biennial reviews of utilities by utilizing the two successive 12-month test
periods ending December 31, 2010, for a Phase I Utility, and utilizing the two
successive 12-month test periods ending December 31, 2011, for a Phase II
Utility, with subsequent proceedings utilizing the two successive 12-month test
periods ending December 31 immediately preceding the year in which such
proceeding is conducted. 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, fair rates of
return on common equity applicable separately to the generation and
distribution services of such utility, and for the two such services combined,
shall be determined by the Commission during each such
biennial review, as follows:.
a. 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
subject to such biennial review, nor shall the Commission set such return more
than 300 basis points higher than such average.
b. In
selecting such majority of peer group investor-owned electric utilities, the
Commission shall first remove from such group the two utilities within such
group that have the lowest reported returns of the group, as well as the two
utilities within such group that have the highest reported 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 biennial
review, the Commission shall identify the utilities in such peer group it
selected for the calculation of such limitation. For purposes of this
subdivision, 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 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 biennial review, and (iv) it is not an
affiliate of the utility subject to such biennial review.
c. 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, such action
being referred to in this section as a Performance Incentive. If the Commission
adopts such Performance Incentive, it shall remain in effect without change
until the next biennial review for such utility is concluded and shall not be
modified pursuant to any provision of the remainder of this subsection.
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 Performance Incentive adopted by
the Commission, or 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, including the determination of whether to adopt a Performance
Incentive and the amount thereof, 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 both the generation and distribution
services is no more than 50 basis points above or below the return as so
determined, such combined return shall not be considered either excessive or
insufficient, respectively.
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 biennial
review.
3. Each such filing by a utility shall make a biennial filing by March 31 of every
other year, beginning in 2011, consisting of pursuant to this subsection shall include
the schedules contained in the Commission's rules governing utility rate
increase applications (20 VAC 5-200-30 5-201-10);
however, if the Commission elects to stagger the dates of the biennial reviews
of utilities as provided in subdivision 1, then Phase I utilities shall
commence biennial filings in 2011 and Phase II utilities shall commence
biennial filings in 2012. Such filing shall encompass the two successive
12-month test periods ending December 31 immediately preceding the year in
which such proceeding is conducted, 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. If
the Commission determines that rates should be revised or credits be applied to
customers' bills pursuant to subdivision 8 or 9, any rate adjustment clauses
previously implemented pursuant to subdivision 4 or 5 or those 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, they
shall thereafter be considered part of the utility's costs, revenues, and
investments for the purposes of future biennial review proceedings.
4. 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, in its proceeding
under this subsection, 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. 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, including a margin to be
recovered on operating expenses, which margin for the purposes of this section
shall be equal to the general rate of return on common equity determined as described in subdivision A 2 of this section pursuant to this subsection.
The Commission shall only approve such a petition if it finds that the program
is in the public interest. As part of such cost recovery, the Commission, if
requested by the utility, shall allow for the recovery of revenue reductions
related to energy efficiency programs. The Commission shall only allow such
recovery to the extent that the Commission determines such revenue has not been
recovered through margins from incremental off-system sales as defined in §
56-249.6 that are directly attributable to energy efficiency programs.
None of the costs of new energy efficiency programs of an
electric utility, including recovery of revenue reductions, shall be assigned
to any customer that has a verifiable history of having used more than 10
megawatts of demand from a single meter of delivery. Nor shall any of the costs
of new energy efficiency programs of an electric utility, including recovery of
revenue reductions, be incurred by any large general service customer as
defined herein that has notified the utility of non-participation in such
energy efficiency program or programs. A large general service customer is a
customer that has a verifiable history of having used more than 500 kilowatts
of demand from a single meter of delivery. Non-participation in energy
efficiency programs shall be allowed by the Commission if 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 November 15, 2009,
promulgate rules and regulations to accommodate the process under which such
large general service customers shall file notice for such an exemption and (i)
establish the administrative procedures by which eligible customers will notify
the utility and (ii) define the standard criteria that must be satisfied by an
applicant in order to notify the utility. In promulgating such rules and
regulations, the Commission may 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. The
notice of non-participation by a large general service customer, to be given by
March 1 of a given year, shall be for the duration of the service life of the
customer's energy efficiency program. The Commission on its own motion may
initiate steps necessary to verify such non-participants' achievement of energy
efficiency if the Commission has a body of evidence that the non-participant
has knowingly misrepresented its energy efficiency achievement. A utility shall
not charge such large general service customer, as defined by the Commission,
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 participation in a renewable
energy portfolio standard program pursuant to §56-585.2 that are not
recoverable under subdivision 6. The Commission shall approve such a petition
allowing the recovery of such costs as are provided for in a program approved
pursuant to §56-585.2; and
e. Projected and actual costs of projects that the Commission
finds to be necessary to comply with state or federal environmental laws or
regulations applicable to generation facilities used to serve the utility's
native load obligations. The Commission shall approve such a petition if it
finds that such costs are necessary to comply with such environmental laws or
regulations. If the Commission determines it would be just, reasonable, and in
the public interest, the Commission may include the enhanced rate of return on
common equity prescribed in subdivision 6 in a rate adjustment clause petition approved hereunder for a project whose purpose is
to reduce the need for construction of new generation facilities by enabling
the continued operation of existing generation facilities. In the event the
Commission includes such enhanced return in such rate adjustment clause increase,
the project that is the subject of such clause petition shall be treated as a
facility described in subdivision 6 for the purposes of this section.
The Commission shall have the authority to determine the
duration or amortization period for any adjustment clause petition approved under this
subdivision.
6. To ensure a reliable and adequate supply of electricity, to
meet the utility's projected native load obligations and to promote economic
development, a utility, in its proceeding
under this subsection, 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, or (iii) one or more major unit modifications of
generation facilities; however, 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 any such facility 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 costs, life-cycle costs, 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. 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 the facility begins commercial operation. 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 the facility
begins commercial operation, 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 petition.
No change shall be made to any Performance Incentive previously adopted by the
Commission in implementing any rate of return under this subdivision. 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) is in the
public interest, and in determining whether to approve such facility, the
Commission shall liberally construe the provisions of this title. 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 200 Between 5 and 15
years
Conventional coal or combined-
cycle combustion turbine 100 Between 10 and 20
years
Generation facilities described in clause (ii) that utilize
simple-cycle combustion turbines shall not 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.
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 from time to time
for such utility pursuant to subdivision 2 this subsection. In any proceeding under this subdivision conducted
prior to the conclusion of the first biennial review for such utility, the
Commission shall determine a general rate of return for such utility in the
same manner as it would in a biennial review proceeding.
Notwithstanding any other provision of this subdivision, if
the Commission finds during the biennial
review a rate case
conducted pursuant to subsection B in
2018, for a Phase II
utility in 2018 which 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, 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 such rate of return as the Commission
finds is in the public interest 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.
7. Any petition filed in a proceeding 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 clause (a) of
subdivision 5, or that are related to facilities and projects described in
clause (i) 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 increase,
whichever is later. Any costs prudently incurred on or after July 1, 2007, by a
utility prior to the filing of such
petition commencement of a
proceeding under this subsection, 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) 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 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,
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 increase, whichever is later.
Any costs prudently incurred after the expiration or termination of capped
rates that are proposed for recovery in a proceeding
under this subsection and are related to other matters
described in subdivisions 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). The
Commission's final order regarding any petition filed pursuant to subdivision
4, 5 or 6 in a proceeding under this subsection 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 increase
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.
8. If the Commission
determines as a result of such biennial review that:
(i) 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 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, 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, the Commission may not order such rate increase 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 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;
(ii) 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 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, the Commission shall, subject
to the provisions of subdivision 9, direct that 60 percent of the amount of
such earnings that were more than 50 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
(iii) Such biennial
review is the second consecutive biennial review in which 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 both
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, the Commission shall, subject
to the provisions of subdivision 9 and in addition to the actions authorized in
clause (ii) of this subdivision, also order reductions to the utility's rates
it finds appropriate. However, 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 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 reduction under the
standards of this sentence, and the amount thereof.
The Commission's final
order regarding such biennial review shall be entered not more than nine months
after the end of the test period, and any revisions in rates or credits so
ordered shall take effect not more than 60 days after the date of the order.
9. If, as a result of
a biennial 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 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,
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 biennial 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 clauses (ii) and
(iii) of subdivision 8 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 above such fair
combined rate of return shall be credited to customers' bills, in lieu of the
provisions of clauses (ii) and (iii) of subdivision 8. Any such credits shall
be amortized and allocated among customer classes in the manner provided by
clause (ii) of subdivision 8. 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 clause (i) of subdivision 8; (iv) revisions to the utility's
rates pursuant to the Commission's rules governing utility rate increase
applications (20 VAC 5-200-30), as permitted by subsection B, occurring after
July 1, 2009; and (v) base rates in effect as of July 1, 2009.
10. For
purposes of this section, the The
Commission shall regulate the rates, terms and conditions of any utility subject to in a proceeding under this section subsection on a stand-alone basis utilizing the actual
end-of-test period capital structure and cost of capital of such utility,
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
clauses (i) and (iii) of subdivision 8, 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.
B. On or after January
1, 2011, the Commission or any party, including the
utility or the Attorney General, may initiate a proceeding to have
the Commission determine rates,
terms and conditions for
the provision of generation, distribution and transmission services for
each investor-owned incumbent electric utility that
are just, reasonable, and nondiscriminatory. Such proceedings shall
be governed by the provisions of Chapter 10 (§56-232 et seq.) of this title
and shall provide fair rates of return on common equity. In a proceeding
conducted pursuant to this subsection:
1. The Commission may
use any methodology to determine rates of return on common equity that the
Commission finds consistent with the public interest;
2. The utility shall
file the schedules contained in the Commission's rules governing utility rate
increase applications (20 VAC 5-201-10)
and such other information as the Commission may deem necessary and appropriate
for a holistic review of all rates, terms and conditions for the provision of
generation, distribution and transmission services by each utility;
3. The Commission
shall analyze the rates of the utility's regulated services on a stand-alone
basis utilizing an appropriate capital structure for the utility's regulated
electric generation, transmission, and distribution operations and a fair and
reasonable cost of capital for the utility;
4. If an incumbent
utility is a wholly owned
subsidiary of a holding company, the Commission shall base its rate
determinations on a hypothetical capital structure for the utility that strikes
a reasonable and appropriate balance between maintenance of the financial
health of the utility and minimizing the costs of capital included in rates;
and
5. The
Commission shall be authorized to permit a utility to
recover, in addition to other costs recoverable in a rate
proceeding under provisions of Chapter 10 (§56-232 et seq.)
of this title, the utility's actual costs, to
the extent not otherwise recoverable in
a proceeding pursuant to subsection A, if the Commission
finds such recovery is just, reasonable, and
in the public interest, of (i) designing and
operating peak-shaving programs as described in subdivision
A 5 b; (ii) designing, implementing, and operating energy efficiency programs
as described in subdivision A 5 c; (iii) participating in a renewable energy
portfolio standard program pursuant to §56-585.2; and (iv) completing projects necessary to comply
with state or federal environmental laws
or regulations applicable to generation facilities used to serve the utility's
native load obligation. A
utility's recovery of such costs shall be determined in connection with a
holistic review of all rates, terms and conditions for the provision of
generation, distribution and transmission services by each utility, and
shall not be recovered through separate adjustment clauses or recovery
mechanisms.
C. 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 (20 VAC 5-200-30 5-201-10);
however, in any such filing, a fair rate of return on common equity shall be
determined pursuant to subdivision 2. Nothing in this
section shall preclude such utility's recovery of fuel and purchased power
costs as provided in §56-249.6.
CD. 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.) of
this title, including specifically §56-235.2.
DE. Nothing in this section
shall preclude the Commission from determining, 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.) of this title.
EF. The Commission shall
promulgate such rules and regulations as may be necessary to implement the
provisions of this section.
§56-585.2. Sale of electricity from renewable sources through
a renewable energy portfolio standard program.
A. As used in this section:
"Renewable energy" shall have the same meaning
ascribed to it in §56-576, provided such renewable energy is (i) generated or
purchased in the Commonwealth or in the interconnection region of the regional
transmission entity of which the participating utility is a member, as it may
change from time to time; (ii) generated by a public utility providing electric
service in the Commonwealth from a facility in which the public utility owns at
least a 49 percent interest and that is located in a control area adjacent to
such interconnection region; or (iii) represented by certificates issued by an
affiliate of such regional transmission entity, or any successor to such
affiliate, and held or acquired by such utility, which validate the generation
of renewable energy by eligible sources in such region. "Renewable
energy" shall not include electricity generated from pumped storage, but
shall include run-of-river generation from a combined pumped-storage and
run-of-river facility.
"Total electric energy sold in the base year" means
total electric energy sold to Virginia jurisdictional retail customers by a
participating utility in calendar year 2007, excluding an amount equivalent to
the average of the annual percentages of the electric energy that was supplied
to such customers from nuclear generating plants for the calendar years 2004
through 2006.
B. Any investor-owned incumbent electric utility may apply to
the Commission for approval to participate in a renewable energy portfolio
standard program, as defined in this section. The Commission shall approve such
application if the applicant demonstrates that it has a reasonable expectation
of achieving 12 percent of its base year electric energy sales from renewable
energy sources during calendar year 2022, and 15 percent of its base year
electric energy sales from renewable energy sources during calendar year 2025,
as provided in subsection D.
C. It is in the public interest for utilities to achieve the
goals set forth in subsection D, such goals being referred to herein as
"RPS Goals". Accordingly, the Commission, in
addition to providing recovery of incremental RPS program costs pursuant to
subsection E, shall may
increase the fair combined rate of return on common equity for each utility
participating in such program by a single Performance
Incentive, as defined in subdivision A 2 of §56-585.1, of 50
basis points such amount as the
Commission finds is just, reasonable, and
in the public interest whenever the
utility attains an RPS Goal established in subsection D. Such Performance Incentive increase in the rate of return
shall first be used in the
calculation of a fair combined rate of return for the
purposes of the immediately succeeding biennial review in a proceeding conducted
pursuant to §56-585.1 after any such RPS Goal is attained, and shall remain in
effect if the utility continues to meet the RPS Goals established in this
section through and including the third succeeding biennial review conducted thereafter for such period as the Commission
finds is just, reasonable, and in the public interest. Any such Performance Incentive, if
implemented, shall be in lieu of any other Performance Incentive reducing or
increasing such utility's fair combined rate of return on common equity for the
same time periods. However, if the utility receives any other Performance
Incentive increasing its fair combined rate of return on common equity by more
than 50 basis points, the utility shall be entitled to such other Performance
Incentive in lieu of this Performance Incentive during the term of such other
Performance Incentive. A utility shall receive double
credit toward meeting the renewable energy portfolio standard for energy
derived from sunlight or from wind.
D. To qualify for the Performance
Incentive established an
increase in the utility's rate of return on
common equity as described in subsection C,
the total electric energy sold by a utility to meet the RPS Goals shall be
composed of the following amounts of electric energy from renewable energy
sources, as adjusted for any sales volumes lost through operation of the
customer choice provisions of subdivision A 3 or A 4 of §56-577:
RPS Goal I: In calendar year 2010, 4 percent of total electric
energy sold in the base year.
RPS Goal II: For calendar years 2011 through 2015, inclusive,
an average of 4 percent of total electric energy sold in the base year, and in
calendar year 2016, 7 percent of total electric energy sold in the base year.
RPS Goal III: For calendar years 2017 through 2021, inclusive,
an average of 7 percent of total electric energy sold in the base year, and in
calendar year 2022, 12 percent of total electric energy sold in the base year.
RPS Goal IV: For calendar years 2023 and 2024, inclusive, an
average of 12 percent of total electric energy sold in the base year, and in
calendar year 2025, 15 percent of total electric energy sold in the base year.
A utility may apply renewable energy sales achieved or
renewable energy certificates acquired during the periods covered by any such
RPS Goal that are in excess of the sales requirement for that RPS Goal to the
sales requirements for any future RPS Goal.
E. A utility participating in such program shall have the
right to recover all incremental costs incurred for the purpose of such
participation in such program, as accrued against
income, through rate adjustment clauses as provided
in (i) with respect to a
proceeding under subsection A of §56-585.1, that
the utility
is entitled to recover under subdivisions A 5 and A 6 of §
56-585.1, including, but not
limited to, administrative costs, ancillary costs, capacity costs, costs of
energy represented by certificates described in subsection A, and, in the case
of construction of renewable energy generation facilities, allowance for funds
used during construction until such time as an
enhanced rate of return, as determined pursuant to subdivision A 6 of §
56-585.1, on construction work in progress is included in rates,
projected construction work in progress, planning, development and construction
costs, life-cycle costs, and costs of infrastructure associated therewith, plus
an enhanced rate of return, as determined pursuant to subdivision A 6 of §
56-585.1 or
(ii) with respect to a proceeding under subsection B of §56-585.1,
that the Commission finds are just,
reasonable, and in the public interest. All
incremental costs of the RPS program shall be allocated to and recovered from
the utility's customer classes based on the demand created by the class and
within the class based on energy used by the individual customer in the class,
except that the incremental costs of the an RPS program approved in a proceeding under subsection A of §
56-581.1 shall not be allocated to or recovered from
customers that are served within the large industrial rate classes of the
participating utilities and that are served at primary or transmission voltage.
F. A utility participating in such program shall apply towards
meeting its RPS Goals any renewable energy from existing renewable energy
sources owned by the participating utility or purchased as allowed by contract
at no additional cost to customers to the extent feasible. A utility
participating in such program shall not apply towards meeting its RPS Goals
renewable energy certificates attributable to any renewable energy generated at
a renewable energy generation source in operation as of July 1, 2007, that is
operated by a person that is served within a utility's large industrial rate
class and that is served at primary or transmission voltage. A participating
utility shall be required to fulfill any remaining deficit needed to fulfill
its RPS Goals from new renewable energy supplies at reasonable cost and in a
prudent manner to be determined by the Commission at the time of approval of
any application made pursuant to subsection B. Utilities participating in such
program shall collectively, either through the installation of new generating
facilities, through retrofit of existing facilities or through purchases of
electricity from new facilities located in Virginia, use or cause to be used no
more than a total of 1.5 million tons per year of green wood chips, bark,
sawdust, a tree or any portion of a tree which is used or can be used for
lumber and pulp manufacturing by facilities located in Virginia, towards
meeting RPS goals, excluding such fuel used at electric generating facilities
using wood as fuel prior to January 1, 2007. A utility with an approved
application shall be allocated a portion of the 1.5 million tons per year in
proportion to its share of the total electric energy sold in the base year, as
defined in subsection A, for all utilities participating in the RPS program. A
utility may use in meeting RPS goals, without limitation, the following
sustainable biomass and biomass based waste to energy resources: mill residue,
except wood chips, sawdust and bark; pre-commercial soft wood thinning; slash;
logging and construction debris; brush; yard waste; shipping crates; dunnage;
non-merchantable waste paper; landscape or right-of-way tree trimmings;
agricultural and vineyard materials; grain; legumes; sugar; and gas produced
from the anaerobic decomposition of animal waste.
G. The Commission shall promulgate such rules and regulations
as may be necessary to implement the provisions of this section including a
requirement that participants verify whether the RPS goals are met in
accordance with this section.
H. Each investor-owned incumbent electric utility shall report
to the Commission annually by November 1 on (i) its efforts, if any, to meet
the RPS Goals, (ii) its overall generation of renewable energy, and (iii)
advances in renewable generation technology that affect activities described in
clauses (i) and (ii).
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