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2009 SESSION
098634338Be it enacted by the General Assembly of Virginia:
1. That §§ 56-577, 56-582, 56-584, 56-585.1, 56-585.2, and 56-585.3 of the Code of Virginia are amended and reenacted as follows:
§ 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. 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. 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.
§ 56-582. Rate caps.
A. The Commission shall establish capped rates, effective January 1, 2001, for each service territory of every incumbent utility as follows:
1. Capped rates shall be established for customers purchasing bundled electric transmission, distribution and generation services from an incumbent electric utility.
2. Capped rates for electric generation services, only, shall also be established for the purpose of effecting customer choice for those retail customers authorized under this chapter to purchase generation services from a supplier other than the incumbent utility during this period.
3. The capped rates established under this section shall be the rates in effect for each incumbent utility as of the effective date of this chapter, or rates subsequently placed into effect pursuant to a rate application filed by an incumbent electric utility with the Commission prior to January 1, 2001, and subsequently approved by the Commission, and made by an incumbent electric utility that is not currently bound by a rate case settlement adopted by the Commission that extends in its application beyond January 1, 2002. If such rate application is filed, the rates proposed therein shall go into effect on January 1, 2001, but such rates shall be interim in nature and subject to refund until such time as the Commission has completed its investigation of such application. Any amount of the rates found excessive by the Commission shall be subject to refund with interest, as may be ordered by the Commission. The Commission shall act upon such applications prior to January 1, 2002. Such rate application and the Commission's approval shall give due consideration, on a forward-looking basis, to the justness and reasonableness of rates to be effective for a period of time ending as late as July 1, 2007. The capped rates established under this section, which include rates, tariffs, electric service contracts, and rate programs (including experimental rates, regardless of whether they otherwise would expire), shall be such rates, tariffs, contracts, and programs of each incumbent electric utility, provided that experimental rates and rate programs may be closed to new customers upon application to the Commission. Such capped rates shall also include rates for new services where, subsequent to January 1, 2001, rate applications for any such rates are filed by incumbent electric utilities with the Commission and are thereafter approved by the Commission. In establishing such rates for new services, the Commission may use any rate method that promotes the public interest and that is fairly compensatory to any utilities requesting such rates.
B. The Commission may adjust such capped rates in connection with the following: (i) utilities' recovery of fuel and purchased power costs pursuant to § 56-249.6, and, if applicable, in accordance with the terms of any Commission order approving the divestiture of generation assets pursuant to § 56-590, (ii) any changes in the taxation by the Commonwealth of incumbent electric utility revenues, (iii) any financial distress of the utility beyond its control, (iv) with respect to cooperatives that were not members of a power supply cooperative on January 1, 1999, and as long as they do not become members, their cost of purchased wholesale power and discounts from capped rates to match the cost of providing distribution services, (v) with respect to cooperatives that were members of a power supply cooperative on January 1, 1999, their recovery of fuel costs, through the wholesale power cost adjustment clauses of their tariffs pursuant to § 56-231.33, and (vi) with respect to incumbent electric utilities that were not, as of the effective date of this chapter, bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, the Commission shall adjust such utilities' capped rates, not more than once in any 12-month period, for the timely recovery of their incremental costs for transmission or distribution system reliability and compliance with state or federal environmental laws or regulations to the extent such costs are prudently incurred on and after July 1, 2004. Any adjustments pursuant to § 56-249.6 and clause (i) of this subsection by an incumbent electric utility that transferred all of its generation assets to an affiliate with the approval of the Commission pursuant to § 56-590 prior to January 1, 2002, shall be effective only on and after July 1, 2007. Notwithstanding the provisions of § 56-249.6, the Commission may authorize tariffs that include incentives designed to encourage an incumbent electric utility to reduce its fuel costs by permitting retention of a portion of cost savings resulting from fuel cost reductions or by other methods determined by the Commission to be fair and reasonable to the utility and its customers.
C. A utility may petition the Commission to terminate the capped rates to all customers any time after January 1, 2004, and such capped rates may be terminated upon the Commission finding of an effectively competitive market for generation services within the service territory of that utility. If its capped rates, as established and adjusted from time to time pursuant to subsections A and B, are continued after January 1, 2004, an incumbent electric utility that is not, as of the effective date of this chapter, bound by a rate case settlement adopted by the Commission that extends in its application beyond January 1, 2002, may petition the Commission, during the period January 1, 2004, through June 30, 2007, for approval of a one-time change in its rates, and if the capped rates are continued after July 1, 2007, such incumbent electric utility may at any time after July 1, 2007, petition the Commission for approval of a one-time change in its rates. Any change in rates pursuant to this subsection by an incumbent electric utility that divested its generation assets with approval of the Commission pursuant to § 56-590 prior to January 1, 2002, shall be in accordance with the terms of any Commission order approving such divestiture. Any petition for changes to capped rates filed pursuant to this subsection shall be governed by the provisions of Chapter 10 (§ 56-232 et seq.) of this title.
D. Until the expiration or termination of capped rates as provided in this section, the incumbent electric utility, consistent with the functional separation plan implemented under § 56-590, shall make electric service available at capped rates established under this section to any customer in the incumbent electric utility's service territory, including any customer that, until the expiration or termination of capped rates, requests such service after a period of utilizing service from another supplier.
E. During the period when capped rates are in effect for an incumbent electric utility, such utility may file with the Commission a plan describing the method used by such utility to assure full funding of its nuclear decommissioning obligation and specifying the amount of the revenues collected under either the capped rates, as provided in this section, or the wires charges, as provided in former § 56-583, that are dedicated to funding such nuclear decommissioning obligation under the plan. The Commission shall approve the plan upon a finding that the plan is not contrary to the public interest.
F. The capped rates established pursuant to this section shall expire on December 31, 2008, unless sooner terminated by the Commission pursuant to the provisions of subsection C; however, rates after the expiration or termination of capped rates shall equal capped rates until such rates are changed pursuant to other provisions of this title.
G. The provisions of this section shall not apply to an incumbent electric utility after the effective date of an order of the Commission entered in a general rate proceeding required by § 56-585.1, or authorized under § 56-585.3, that first establishes post-capped rate period rates, terms, and conditions for the provision of services by the incumbent electric utility.
§ 56-584. Stranded costs.
A. Just and reasonable net stranded
costs, to the extent that they exceed zero value in total for the incumbent
electric utility, shall be recoverable by each incumbent electric utility
provided each incumbent electric utility shall only recover its just and
reasonable net stranded costs through either
capped rates as provided in § 56-582. To the extent not preempted by federal
law, the establishment by the Commission of wires charges for any distribution
cooperative shall be conditioned upon such cooperative entering into binding
commitments by which it will pay to any power supply cooperative of which such
distribution cooperative is or was a member, as compensation for such power
supply cooperative's stranded costs, all or part of the proceeds of such wires
charges, as determined by the Commission.
B. In the first general rate proceeding required by § 56-585.1, or authorized under § 56-585.3, that establishes post-capped-rate-period rates, terms, and conditions for the provision of services by the incumbent electric utility, the Commission shall determine (i) the dollar amount of actual stranded cost recoveries under capped rates for the utility since the initiation of capped rates and (ii) the dollar amount of stranded costs actually incurred by each utility since the initiation of capped rates.
C. The Commission shall require each incumbent electric utility to refund to the utility’s retail customers in the Commonwealth an amount equal to the amount, if any, by which the actual stranded cost recoveries under capped rates for the utility since the initiation of capped rates determined pursuant to clause (i) of subsection B exceeds the stranded costs actually incurred by each utility since the initiation of capped rates determined pursuant to clause (ii) of subsection B. The refunds shall be made on a uniform cents-per-kilowatt-hour basis using each customer’s metered kilowatt-hour usage for the 12 months ended December 31, 2008.
§ 56-585.1. Regulation of rates of investor-owned incumbent electric utilities after December 31, 2008.
A. In each rate proceeding subsequent to the termination or expiration of capped rates, the Commission shall determine rates for each investor-owned incumbent utility that are just, reasonable, and nondiscriminatory.
During the first six months of B. In a
proceeding initiated by the Commission during 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, subject to notice and opportunity for hearing.
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 and shall provide
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 rates of 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 completion of the utility's next rate proceeding. 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) 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,
C. Subsequent to the Commission, after notice and opportunity for hearing, shall
conduct biennial reviews Commission’s
establishment of new rates as determined in rate proceedings initiated by the
Commission during 2009, the Commission or any party, including, but not limited
to, the utility or the Attorney General, may request a rate change subject to
the requirement that the proponent of a rate change must demonstrate that the
proposed rate change is just, reasonable, and nondiscriminatory.
D. Each incumbent utility
shall make a biennial filing by March 31 of every other year, beginning in
2011, consisting of the schedules contained in the Commission's rules governing
utility rate increase applications (20 VAC 5-200-30) and such other information
as the Commission may deem necessary and appropriate for a holistic review of
all of the utility’s rates and charges for electric service. 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.
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. Such
filing shall encompass the utility’s actual costs and revenue for the two
successive 12-month test periods ending December 31 immediately preceding the
year in which such review 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. Commencing in the first six months of 2011 and
biennially thereafter,
each investor-owned incumbent electric utility shall file with the Commission a
holistic review of the all
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. 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 including all surcharges, rate riders, and rate adjustment clause mechanisms. Upon review of such
information the Commission may, after notice and opportunity for hearing, order changes in the utility’s rates to ensure that such rates continue to be
just, reasonable, and
nondiscriminatory. 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. In
addition to other considerations:
e1. 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.;
and
f2. The
determination of such returns, including the determination Determinations 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 and reflect
consideration of the impact of the incentive, if
any, on the utility's risk profile and fair rate of 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 utility shall make a biennial filing
by March 31 of every other year, beginning in 2011, consisting of the schedules
contained in the Commission's rules governing utility rate increase applications
(20 VAC 5-200-30); 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 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 of providing
incentives for the utility to design and operate fair and effective
demand-management, conservation, energy efficiency, and load management
programs. The Commission shall approve such a petition if it finds that the
program is in the public interest and that the need for the incentives is
demonstrated with reasonable certainty; provided that the Commission shall allow
the recovery of such costs as it finds are reasonable;
c. 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
d. 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
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, the project that is the subject
of such clause 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
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 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. 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. 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 conducted for a
Phase II utility in 2018 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.
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 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, whichever is later. 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) 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 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 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.
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.
10E. 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 an
appropriate capital structure for the utility's
regulated electric generation, transmission, and distribution
operations and a fair and reasonable cost of capital of for
such a utility, unless.
Where an incumbent utility is a wholly-owned subsidiary
of a holding company, 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 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.
BF.
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); 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.
CG. 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.
DH.
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.
EI. 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, 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
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 whenever the utility attains an RPS Goal established in
subsection D. Such Performance Incentive increase in the rate of return on common equity shall first be
used in the calculation of a fair combined rate of return for the purposes of
the immediately succeeding biennial review 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. 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 increase in the fair combined rate of
return on common equity established 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.
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 subdivisions A 5 and A 6 of to
the extent provided in § 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.
All recoverable 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 RPS program 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).
§ 56-585.3. Regulation of cooperative rates after rate caps.
After the expiration or termination of capped rates, the rates, terms and conditions of distribution electric cooperatives subject to Article 1 (§ 56-231.15 et seq.) of Chapter 9.1 of this title shall be regulated in accordance with the provisions of Chapters 9.1 (§ 56-231.15 et seq.) and 10 (§ 56-232 et seq.) of this title, as modified by the following provisions:
1. Except for energy related cost (fuel cost), the Commission shall not require any cooperative to adjust, modify, or revise its rates, by means of riders or otherwise, to reflect changes in wholesale power cost which occurred during the capped rate period, other than in a general rate proceeding.
2. Each cooperative may, without Commission approval or the requirement of any filing other than as provided in this subdivision, upon an affirmative resolution of its board of directors, increase or decrease all classes of its rates for distribution services at any time, provided, however, that such adjustments will not effect a cumulative net increase or decrease in excess of 5 percent in such rates in any three year period. Such adjustments will not affect or be limited by any existing fuel or wholesale power cost adjustment provisions. The cooperative will promptly file any such revised rates with the Commission for informational purposes.
3. Each cooperative may, without Commission approval, upon an affirmative resolution of its board of directors, make any adjustment to its terms and conditions that does not affect the cooperative's revenues from the distribution or supply of electric energy. In addition, a cooperative may make such adjustments to any pass-through of third-party service charges and fees, and to any fees, charges and deposits set out in Schedule F of such cooperative's Terms and Conditions filed as of January 1, 2007. The cooperative will promptly file any such amended terms and conditions with the Commission for informational purposes.
4. A cooperative may, at any time after the expiration or
termination of capped rates, petition the Commission for approval of one or
more rate adjustment clauses for the timely and current recovery from customers
of the costs described in subdivisions A 5 b and d of §
56-585.1 of providing incentives for the cooperative to
design and operate fair
and effective demand management, conservation, energy efficiency,
and load management programs and costs of projects that the Commission finds to be necessary to comply with state and federal environmental laws
applicable to the cooperative's generation facilities used
to serve its native load obligations.
5. None of the adjustments described in subdivisions 2 through 4 will apply to the rates paid by any customer that takes service by means of dedicated distribution facilities and had noncoincident peak demand in excess of 90 megawatts in calendar year 2006.
Nothing in this section shall be deemed to grant to a cooperative any authority to amend or adjust any terms and conditions of service or agreements regarding pole attachments or the use of the cooperative's poles or conduits.