SB882: Electric utility regulation; rebundles charges for transmission, etc., into base rates.
SENATE BILL NO. 882
Be it enacted by the General Assembly of Virginia:
1. That §§ 15.2-1901, 56-231.24, 56-234.2, 56-235.2, 56-238, 56-249.6, 56-576, 56-578, 56-579, 56-580, 56-581, 56-585.1, 56-585.2, 56-585.3, 56-590, 56-592, 56-593, 56-594, and 58.1-400.3 of the Code of Virginia are amended and reenacted as follows:
§ 15.2-1901. Condemnation authority.
A. In addition to the authority granted to localities pursuant to any applicable charter provision or other provision of law, whenever a locality is authorized to acquire real or personal property or property interests for a public use, it may do so by exercise of the power of eminent domain, except as provided in subsection B.
B. A locality may acquire property or property interests
outside its boundaries by exercise of the power of eminent domain only if such
authority is expressly conferred by general law or special act. However, cities
and towns shall have the right to acquire property outside their boundaries for
the purposes set forth in § 15.2-2109 by exercise of the power of eminent
domain. The exercise of such condemnation authority by a
city or town shall not be construed to exempt the municipality from the
provisions of subsection F of § 56-580.
§ 56-231.24. Power to dispose of property.
No cooperative may sell, lease or dispose of all or
substantially all of its property (other than property which, in the judgment
of the board, is neither necessary nor useful in operating and maintaining the
cooperative's system and which in any one year shall not exceed fifty percent
in value of the value of all the property of the cooperative, or merchandise),
unless authorized to do so by the votes of at least a two-thirds majority of
its members; however, a cooperative (i) may mortgage, finance (including,
without limitation, pursuant to a sale and leaseback or lease and leaseback
transaction), or otherwise encumber its assets by a vote of at least two-thirds
of its board of directors; (ii) may sell or transfer its assets to another
cooperative upon the vote of a majority of its members at any regular or
special meeting if the notice of such meeting contains a copy of the terms of
the proposed sale or transfer; or (iii)
may sell or transfer distribution system facilities to a city or town at any
time following the annexation of additional territory pursuant to § 56-265.4:2
by a vote of at least two-thirds of its board of directors; or
(iv) may sell, lease or dispose of its property to an affiliate pursuant to a
plan approved by the Commission in accordance with subsection B of § 56-590 by
a vote of at least two-thirds of the members of the Board.
§ 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 changes 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.
§ 56-238. Suspension of proposed rates, etc.; investigation; effectiveness of rates pending investigation and subject to bond; fixing reasonable rates, etc.
A. The
Commission, either upon complaint or on its own motion,
may:
1. May
suspend the enforcement of any or all of the proposed rates, tolls, charges,
rules or regulations of any public utility except an investor-owned electric
public utility for a period not exceeding 150 days from the date of filing, and the Commission shall; and
2. Shall
suspend the enforcement of all of the proposed rates, tolls, charges, rules or
regulations of an investor-owned electric public utility until the Commission's
final order in the proceeding, during which except as provided in subdivision A 6 of
§ 56-585.1.
B. During times that the proposed rates, tolls, charges, rules or regulations are suspended, the Commission shall investigate the reasonableness or justice of the proposed rates, tolls, charges, rules and regulations and thereupon fix and order substituted therefor such rates, tolls, charges, rules and regulations as shall be just and reasonable.
C. The
Commission's final order in such a proceeding involving an investor-owned electric
public utility that is filed after
January 1, 2010, shall be entered not more than nine months
after the date of the filing is
complete, except as provided in
subdivision A 6 of § 56-585.1, at
which time the suspension period shall expire, and any revisions in rates or
credits so ordered shall take effect not more than 60 days after the date of
the order.
D. Notice of the suspension of any proposed rate, toll, charge, rule or regulation shall be given by the Commission to the public utility, prior to the expiration of the 30 days' notice to the Commission and the public heretofore provided for.
E. If
the proceeding has not been concluded and an order made at the expiration of
the suspension period, after notice to the Commission by the public utility
making the filing, the proposed rates, tolls, charges, rules or regulations
shall go into effect. Where increased rates, tolls or charges are thus made
effective, the Commission shall, by order, require the public utility to
furnish a bond, to be approved by the Commission, to refund any amounts ordered
by the Commission, to keep accurate accounts in detail of all amounts received
by reason of such increase, and upon completion of the hearing and decision, to
order such public utility to refund, with interest at a rate set by the
Commission, the portion of such increased rates, tolls or charges by its
decision found not justified. The Commission shall prescribe all necessary
rules and regulations to effectuate the purposes of this section on or before September 1, 1980.
F. This section shall not apply to proceedings conducted pursuant to § 56-245 or 56-249.6.
§ 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. In addition, 75 percent of the total annual margins
from off-system sales 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
charges shall be applied to fuel factor expenses and (ii) any such net losses
shall not be considered in the biennial reviews of electric utilities conducted
pursuant to § 56-585.1. 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. The Commission
may, to the extent deemed appropriate, offset against fuel costs and purchased
power costs to be recovered hereunder the margins from off-system sales; 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.
§ 56-576. Definitions.
As used in this chapter:
"Affiliate" means any person that controls, is controlled by, or is under common control with an electric utility.
"Aggregator"
means a person that, as an agent or intermediary, (i) offers to purchase, or
purchases, electric energy or (ii) offers to arrange for, or arranges for, the
purchase of electric energy, for sale to, or on behalf of, two or more retail
customers not controlled by or under common control with such person. The
following activities shall not, in and of themselves, make a person an
aggregator under this chapter: (i) furnishing legal services to two or more
retail customers, suppliers or aggregators; (ii) furnishing educational,
informational, or analytical services to two or more retail customers, unless
direct or indirect compensation for such services is paid by an aggregator or
supplier of electric energy; (iii) furnishing educational, informational, or
analytical services to two or more suppliers or aggregators; (iv) providing
default service under § 56-585; (v) engaging in activities of a retail electric
energy supplier, licensed pursuant to § 56-587, which are authorized by such
supplier's license; and (vi) engaging in actions of a retail customer, in
common with one or more other such retail customers, to issue a request for
proposal or to negotiate a purchase of electric energy for consumption by such
retail customers.
"Combined heat and power" means a method of using waste heat from electrical generation to offset traditional processes, space heating, air conditioning, or refrigeration.
"Commission"
means the State Corporation Commission.
"Cooperative" means a utility formed under or subject to Chapter 9.1 (§ 56-231.15 et seq.) of this title.
"Covered
entity" means a provider in the Commonwealth of an electric service not
subject to competition but shall not include default service providers.
"Covered
transaction" means an acquisition, merger, or consolidation of, or other
transaction involving stock, securities, voting interests or assets by which
one or more persons obtains control of a covered entity.
"Curtailment" means inducing retail customers to reduce load during times of peak demand so as to ease the burden on the electrical grid.
"Customer
choice" means the opportunity for a retail customer in the Commonwealth to
purchase electric energy from any supplier licensed and seeking to sell
electric energy to that customer.
"Demand response" means measures aimed at shifting time of use of electricity from peak-use periods to times of lower demand by inducing retail customers to curtail electricity usage during periods of congestion and higher prices in the electrical grid.
"Distribute," "distributing," or "distribution of" electric energy means the transfer of electric energy through a retail distribution system to a retail customer.
"Distributor"
means a person owning, controlling, or operating a retail distribution system
to provide electric energy directly to retail customers.
"Electric utility" means any person that generates,
transmits, or distributes electric energy for use by retail customers in the
Commonwealth, including any investor-owned electric utility, or cooperative
electric utility, or electric utility
owned or operated by a municipality.
"Energy efficiency program" means a program that reduces the total amount of electricity that is required for the same process or activity implemented after the expiration of capped rates. Energy efficiency programs include equipment, physical, or program change designed to produce measured and verified reductions in the amount of electricity required to perform the same function and produce the same or a similar outcome. Energy efficiency programs may include, but are not limited to, (i) programs that result in improvements in lighting design, heating, ventilation, and air conditioning systems, appliances, building envelopes, and industrial and commercial processes; and (ii) measures, such as but not limited to the installation of advanced meters, implemented or installed by utilities, that reduce fuel use or losses of electricity and otherwise improve internal operating efficiency in generation, transmission, and distribution systems. Energy efficiency programs include demand response, combined heat and power and waste heat recovery, curtailment, or other programs that are designed to reduce electricity consumption so long as they reduce the total amount of electricity that is required for the same process or activity. Utilities shall be authorized to install and operate such advanced metering technology and equipment on a customer's premises; however, nothing in this chapter establishes a requirement that an energy efficiency program be implemented on a customer's premises and be connected to a customer's wiring on the customer's side of the inter-connection without the customer's expressed consent.
"Generate," "generating," or "generation of" electric energy means the production of electric energy.
"Generator"
means a person owning, controlling, or operating a facility that produces
electric energy for sale.
"Incumbent
electric utility" means each electric utility in the Commonwealth that,
prior to July 1, 1999, supplied electric energy to retail customers located in
an exclusive service territory established by the Commission.
"Independent system operator" means a person that may receive or has received, by transfer pursuant to this chapter, any ownership or control of, or any responsibility to operate, all or part of the transmission systems in the Commonwealth.
"Measured and verified" means a process determined pursuant to methods accepted for use by utilities and industries to measure, verify, and validate energy savings and peak demand savings. This may include the protocol established by the United States Department of Energy, Office of Federal Energy Management Programs, Measurement and Verification Guidance for Federal Energy Projects, measurement and verification standards developed by the American Society of Heating, Refrigeration and Air Conditioning Engineers (ASHRAE), or engineering-based estimates of energy and demand savings associated with specific energy efficiency measures, as determined by the Commission.
"Municipality" means a city, county, town, authority, or other political subdivision of the Commonwealth.
"Peak-shaving" means measures aimed solely at shifting time of use of electricity from peak-use periods to times of lower demand by inducing retail customers to curtail electricity usage during periods of congestion and higher prices in the electrical grid.
"Person" means any individual, corporation, partnership, association, company, business, trust, joint venture, or other private legal entity, and the Commonwealth or any municipality.
"Renewable energy" means energy derived from sunlight, wind, falling water, biomass, sustainable or otherwise, (the definitions of which shall be liberally construed), energy from waste, municipal solid waste, wave motion, tides, and geothermal power, and does not include energy derived from coal, oil, natural gas or nuclear power. Renewable energy shall also include the proportion of the thermal or electric energy from a facility that results from the co-firing of biomass.
"Retail customer" means any person that purchases retail electric energy for its own consumption at one or more metering points or nonmetered points of delivery located in the Commonwealth.
"Retail electric energy" means electric energy sold for ultimate consumption to a retail customer.
"Revenue reductions related to energy efficiency programs" means reductions in the collection of total non-fuel revenues, previously authorized by the Commission to be recovered from customers by a utility, that occur due to measured and verified decreased consumption of electricity caused by energy efficiency programs approved by the Commission and implemented by the utility, less the amount by which such non-fuel reductions in total revenues have been mitigated through other program-related factors, including reductions in variable operating expenses.
"Supplier"
means any generator, distributor, aggregator, broker, marketer, or other person
who offers to sell or sells electric energy to retail customers and is licensed
by the Commission to do so, but it does not mean a generator that produces
electric energy exclusively for its own consumption or the consumption of an
affiliate.
"Supply" or
"supplying" electric energy means the sale of or the offer to sell
electric energy to a retail customer.
"Transmission of," "transmit," or
"transmitting" electric energy means the transfer of electric energy
through the Commonwealth's interconnected transmission grid from a generator to either a distributor or a retail customer.
"Transmission system" means those facilities and equipment that are required to provide for the transmission of electric energy.
§ 56-578. Nondiscriminatory access to transmission and distribution system.
A. All distributors electric utilities
shall have the obligation to connect any retail customer, including those using
distributed generation, located within its service territory to those
facilities of the distributor electric utility
that are used for delivery of retail electric energy, subject to Commission
rules and regulations and approved tariff provisions relating to connection of
service.
B. Except as otherwise provided in this chapter, every distributor electric utility shall provide
distribution service within its service territory on a basis which is just,
reasonable, and not unduly discriminatory to
suppliers of electric energy, including distributed generation, as the
Commission may determine. The
distribution services provided to each supplier of electric energy shall be
comparable in quality to those provided by the distribution utility to itself
or to any affiliate.
C. The Commission shall establish interconnection standards to ensure transmission and distribution safety and reliability, which standards shall not be inconsistent with nationally recognized standards acceptable to the Commission. In adopting standards pursuant to this subsection, the Commission shall seek to prevent barriers to new technology and shall not make compliance unduly burdensome and expensive. The Commission shall determine questions about the ability of specific equipment to meet interconnection standards.
D. The Commission shall consider developing expedited permitting processes for small generation facilities of fifty megawatts or less. The Commission shall also consider developing a standardized permitting process and interconnection arrangements for those power systems less than 500 kilowatts which have demonstrated approval from a nationally recognized testing laboratory acceptable to the Commission.
E. Upon the separation
and deregulation of the generation function and services of incumbent electric
utilities, the The
Commission shall retain jurisdiction over utilities' electric transmission
function and services, to the extent not preempted by federal law. Nothing in
this section shall impair the Commission's authority under §§ 56-46.1, 56-46.2,
and 56-265.2 with respect to the construction of electric transmission
facilities.
§ 56-579. Regional transmission entities.
A. As set forth in §
56-577, each incumbent Each electric utility owning, operating, controlling, or
having an entitlement to transmission capacity shall join or establish may
be a member of or participate in a regional transmission
entity, which hereafter may be referred to as
"RTE," to which such utility
shall transfer the management and control of its transmission assets, subject
to the following:
1. No such incumbent
electric utility shall transfer to any person any ownership or control of, or any
responsibility to operate, any portion of any transmission system located in
the Commonwealth prior to July 1, 2004, and without upon obtaining, following
notice and hearing, the prior approval of the Commission, as
hereinafter provided. However, each incumbent electric utility shall file an
application for approval pursuant to this section by July 1, 2003, and shall
transfer management and control of its transmission assets to a regional
transmission entity by January 1, 2005, subject to Commission approval as
provided in this section.
2 B. The Commission shall
develop rules and regulations under which any such incumbent electric utility
owning, operating, controlling, or having an entitlement to transmission
capacity within the Commonwealth,
may transfer all or part of such control, ownership or responsibility to an
RTE, upon such terms and conditions that the Commission determines will:
a 1. Promote:
(1) Practices(i) practices
for the reliable planning, operating, maintaining, and upgrading of the transmission
systems and any necessary additions thereto;
and
(2) Policies (ii) policies for the pricing
and access for service over such systems that are safe, reliable, efficient,
not unduly discriminatory and consistent with the orderly development of competition
in the Commonwealth;
b 2. Be consistent with lawful
requirements of the Federal Energy Regulatory Commission;
c 3. Be effectuated on terms
that fairly compensate the transferor; and
d 4. Generally promote the
public interest, and are consistent with (i)
ensuring that consumers' needs for economic and reliable transmission are met and (ii) meeting the transmission needs of electric generation
suppliers both within and without this Commonwealth, including those that do
not own, operate, control or have an entitlement to transmission capacity.
B C. The Commission shall also
adopt rules and regulations, with appropriate public input, establishing
elements of regional transmission entity structures essential to the public
interest, which elements shall be applied by the Commission in determining
whether to authorize transfer of ownership or control from an incumbent
electric utility to a regional transmission entity.
C D. The Commission shall, to
the fullest extent permitted under federal law, participate in any and all
proceedings concerning regional transmission entities furnishing transmission
services within the Commonwealth, before the Federal Energy Regulatory
Commission. Such participation may include such intervention as is permitted
state utility regulators under Federal Energy Regulatory Commission rules and
procedures.
D E. Nothing in this section
shall be deemed to abrogate or modify:
1. The Commission's authority over transmission line or
facility construction, enlargement or acquisition within this Commonwealth, as
set forth in Chapter 10.1 (§ 56-265.1 et seq.) of
this title;
2. The laws of this Commonwealth concerning the exercise of
the right of eminent domain by a public service corporation pursuant to the
provisions of Article 5 (§ 56-257 et seq.) of Chapter 10 of
this title; or
3. The Commission's authority over retail electric energy sold
to retail customers within the Commonwealth by
licensed suppliers of electric service, including necessary reserve
requirements, all as specified in § 56-587.
E F. For purposes of this
section, transmission capacity shall not include capacity that is primarily
operated in a distribution function, as determined by the Commission, taking
into consideration any binding federal precedents.
F G. Any request to the
Commission for approval of such transfer of ownership or control of or
responsibility for transmission facilities shall include a study of the
comparative costs and benefits thereof, which study shall analyze the economic
effects of the transfer on consumers, including the effects of transmission
congestion costs. The Commission may approve such a transfer if it finds, after
notice and hearing, that the transfer satisfies the conditions contained in
this section.
G H. The Commission shall report
annually to the Commission on Electric Utility Regulation its assessment of the
practices and policies of the RTE. Such report shall set forth actions taken by
the Commission regarding requests for the approval of any transfer of ownership
or control of transmission facilities to an RTE, including a description of the
economic effects of such proposed transfers on consumers.
§ 56-580. Commission authority to regulate generation, transmission, and distribution of electric energy; permitting generation facilities.
A. Subject to the
provisions of § 56-585.1, the The
Commission shall continue to
regulate pursuant to this title the generation and
distribution of retail electric energy to retail customers in the Commonwealth
and, to the extent not prohibited by federal law, the transmission of electric
energy in the Commonwealth.
B. The Commission shall continue to
regulate, to the extent not prohibited by federal law, the reliability, quality
and maintenance by transmitters and distributors electric utilities
of their generation, transmission, and retail distribution
systems.
C. The Commission shall develop codes of conduct governing the
conduct of incumbent electric utilities
and affiliates thereof when any such affiliates provide, or control any entity
that provides, generation, distribution, or transmission services, to the extent necessary to prevent impairment of
competition. Nothing in this chapter shall prevent an incumbent electric utility
from offering metering options to its customers.
D. The Commission shall permit the construction and operation
of electrical generating facilities in Virginia upon a finding that such
generating facility and associated facilities (i) will have no material adverse
effect upon reliability of electric service provided by any regulated public
utility, (ii) are required by the public convenience and necessity, if a petition for such permit is filed after July
1, 2007, and if they are to be
constructed and operated by any regulated utility whose rates are regulated
pursuant to § 56-585.1, and (iii) are not otherwise contrary to the public
interest. In review of a petition for a certificate to construct and operate a
generating facility described in this subsection, the Commission shall give consideration
to the effect of the facility and associated facilities on the environment and
establish such conditions as may be desirable or necessary to minimize adverse
environmental impact as provided in § 56-46.1, unless exempt as a small
renewable energy project for which the Department of Environmental Quality has
issued a permit by rule pursuant to Article 5 (§ 10.1-1197.5 et seq.) of
Chapter 11.1 of Title 10.1. In order to avoid duplication of governmental
activities, any valid permit or approval required for an electric generating
plant and associated facilities issued or granted by a federal, state or local
governmental entity charged by law with responsibility for issuing permits or
approvals regulating environmental impact and mitigation of adverse environmental
impact or for other specific public interest issues such as building codes,
transportation plans, and public safety, whether such permit or approval is
prior to or after the Commission's decision, shall be deemed to satisfy the
requirements of this section with respect to all matters that (i) are governed
by the permit or approval or (ii) are within the authority of, and were
considered by, the governmental entity in issuing such permit or approval, and
the Commission shall impose no additional conditions with respect to such
matters. Nothing in this section shall affect the ability of the Commission to
keep the record of a case open. Nothing in this section shall affect any right
to appeal such permits or approvals in accordance with applicable law. In the
case of a proposed facility located in a region that was designated as of July
1, 2001, as serious nonattainment for the one-hour ozone standard as set forth
in the federal Clean Air Act, the Commission shall not issue a decision
approving such proposed facility that is conditioned upon issuance of any
environmental permit or approval. The Commission shall complete any proceeding
under this section, or under any provision of the Utility Facilities Act (§
56-265.1 et seq.), involving an application for a certificate, permit, or
approval required for the construction or operation by a public utility of a
small renewable energy project as defined in § 10.1-1197.5, within nine months
following the utility's submission of a complete application therefore. Small
renewable energy projects as defined in § 10.1-1197.5 are in the public
interest and in determining whether to approve such project, the Commission
shall liberally construe the provisions of this title.
E. Nothing in this section shall impair the distribution
service territorial rights of incumbent
electric utilities, and incumbent
electric utilities shall continue to provide distribution services within their
exclusive service territories as established by the Commission. Subject to the provisions of § 56-585.1, the The Commission shall continue to exercise its existing
authority over the provision of electric generation,
transmission, and distribution services to retail customers
in the Commonwealth as provided in this
title, including, but not limited to, the
authority contained in Chapters 10 (§ 56-232 et seq.) and
10.1 (§ 56-265.1 et seq.) of this title.
F. Nothing in this chapter shall impair the exclusive
territorial rights of an electric utility owned or operated by a municipality
as of July 1, 1999, or by an authority created by a governmental unit exempt
from the referendum requirement of § 15.2-5403. Nor
shall any provision of this chapter apply to any such electric utility unless
(i) that municipality or that authority created by a governmental unit exempt
from the referendum requirement of § 15.2-5403 elects to have this chapter
apply to that utility or (ii) that utility, directly or indirectly, sells,
offers to sell or seeks to sell electric energy to any retail customer eligible
to purchase electric energy from any supplier in accordance with § 56-577 if
that retail customer is outside the geographic area that was served by such
municipality as of July 1, 1999, except (a) any area within the municipality
that was served by an incumbent public utility as of that date but was
thereafter served by an electric utility owned or operated by a municipality or
by an authority created by a governmental unit exempt from the referendum
requirement of § 15.2-5403 pursuant to the terms of a franchise agreement
between the municipality and the incumbent public utility, or (b) where the
geographic area served by an electric utility owned or operated by a
municipality is changed pursuant to mutual agreement between the municipality
and the affected incumbent public utility in accordance with § 56-265.4:1. If
an electric utility owned or operated by a municipality as of July 1, 1999, or
by an authority created by a governmental unit exempt from the referendum requirement
of § 15.2-5403 is made subject to the provisions of this chapter pursuant to
clause (i) or (ii) of this subsection, then in such event the provisions of
this chapter applicable to incumbent electric utilities shall also apply to any
such utility, mutatis mutandis.
G. The applicability of all provisions of this chapter except
§ 56-594 shall not apply to any
investor-owned incumbent
electric utility supplying electric service to retail customers on January 1,
2003, whose service territory assigned to it by the Commission is located
entirely within Dickenson, Lee, Russell, Scott, and Wise Counties shall be suspended effective July 1, 2003, so
long as such utility does not provide retail electric services in any other
service territory in any jurisdiction to customers who have the right to
receive retail electric energy from another supplier. During any such suspension period, the Such utility's rates shall be (i) its capped rates established pursuant to §
56-582 for the duration of the capped rate period established thereunder, and
(ii) determined thereafter
by the Commission on the basis of such utility's prudently incurred costs
pursuant to Chapter 10 (§ 56-232 et seq.) of
this title.
H. The expiration date
of any certificates granted by the Commission pursuant to subsection D, for
which applications were filed with the Commission prior to July 1, 2002, shall
be extended for an additional two years from the expiration date that otherwise
would apply.
§ 56-581. Regulation of rates subject to Commission's jurisdiction.
A. After the
expiration or termination of capped rates except as provided in § 56-585.1 Beginning January 1,
2009, the Commission shall
regulate the rates of investor-owned incumbent
electric utilities for the transmission of electric energy, to the extent not
prohibited by federal law, and for, the generation of electric
energy, and the distribution of
electric energy to retail customers pursuant to § 56-585.1.
B. Beginning July January 1, 1999 2009,
and thereafter, no cooperative that was a member of
a power supply cooperative on January 1, 1999, shall be obligated to file any
rate rider as a consequence of an increase or decrease in the rates, other than
fuel costs, of its wholesale supplier, nor must any adjustment be made to such
cooperative's rates as a consequence thereof the Commission shall regulate the rates of
cooperatives for the transmission of electric energy, to the extent not
prohibited by federal law, the generation of electric energy, and
the distribution of electric energy to retail customers pursuant to § 56-585.3.
C. Except for the
provision of default services under § 56-585 or emergency services in § 56-586, nothing Nothing in this chapter shall authorize the Commission to
regulate the rates or charges for electric service to the Commonwealth and its
municipalities.
§ 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. The Commission may
increase or decrease such combined rate of return by up to 100 basis points based
on the generating plant performance, customer service, and operating efficiency
of a utility, as compared to nationally recognized standards determined by the
Commission to be appropriate for such purposes. In such a proceeding, the
Commission shall determine the rates that the utility may charge until such
rates are adjusted. If the Commission finds that the utility's combined rate of
return on common equity is more than 50 basis points below the combined rate of
return as so determined, it shall be authorized to order increases to the
utility's rates necessary to provide the opportunity to fully recover the costs
of providing the utility's services and to earn not less than such combined
rate of return. If the Commission finds that the utility's combined rate of
return on common equity is more than 50 basis points above the combined rate of
return as so determined, it shall be authorized either (i) to order reductions
to the utility's rates it finds appropriate, provided that the Commission may
not order such rate reduction unless it finds that the resulting rates will
provide the utility with the opportunity to fully recover its costs of
providing its services and to earn not less than the fair rates of return on
common equity applicable to the generation and distribution services; or (ii)
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,. Such proceedings shall
be governed by the provisions of Chapter 10 (§ 56-232 et seq.), except as
modified herein. Proceedings under this section shall be
subject to the following provisions:
1. Rates, terms and conditions for each service generation,
distribution, and transmission
services shall be reviewed separately on an unbundled a bundled basis, and such reviews shall be conducted
in a single, combined biennial review proceeding.
The Each such utility shall make a biennial filing by March 31 of every other
year. Unless the Commission finds that it is in the public interest to
adjust the schedule for biennial filings in order to have the reviews for each
Phase I Utility and Phase II Utility
conducted in the same year: (i) biennial review proceedings shall commence in 2011
for each Phase I Utility and in 2012 for each Phase II Utility; (ii) the
first such review for a Phase I Utility 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 ; and (iii) the first such review
for a Phase II Utility shall utilize the two successive
12-month test periods ending December 31, 2011,
for a Phase II Utility, with subsequent.
Subsequent biennial review proceedings utilizing shall utilize the two successive 12-month test periods
ending December 31 immediately preceding the year in which such proceeding is
conducted. Filings shall consist
of the schedules contained in the Commission's rules governing utility rate
increase applications and shall encompass the
two successive 12-month test periods ending December 31 immediately preceding
the year in which such proceeding is conducted. 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. 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, A fair rates rate of return on common
equity applicable separately
to the transmission, 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 determining a utility's fair rate of return on
common equity, 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. compare the risks
of the utility relative to the corresponding risks of any proxy utilities or
utility holding companies used for the
purpose of estimating the costs of common equity. Such risks may include a
comparison of the regulatory system
applicable to the subject utility to the
systems applicable to the proxy companies in other states in order to determine whether
the rates of return that comparable utilities are
authorized to earn in other states reflect comparable risks borne by the utility
under the state's regulatory system,
including the extent to which fuel and purchased power costs
and investments in certain facilities are
recoverable through separate proceedings;
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 d. 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. operating in the
Commonwealth or in other states, which utilities are determined by the Commission to
be comparable with the utility;
f e. 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 after considering
any return on common equity or and other matters determined
with regard to facilities described in subdivision 6. 4 f;
g f. If the combined rate of return on common equity earned by both the generation and distribution services the utility
is no more than 50 basis points above or below the return as so determined,
such combined return shall not may
be considered either excessive or
insufficient, respectively. by the Commission to be within an authorized
reasonable range; and
h g. 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 transmission-related
costs incurred by the utility shall be deemed reasonable and prudent recoverable through the utility's base rates: (i) reasonable and prudent
costs for transmission
services, including, without limitation, charges for new
and existing transmission facilities, administrative charges, and ancillary
service charges designed to recover transmission costs
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) reasonable and prudent costs charged to the utility
that are associated with in
implementing 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. As
used in this section, a utility's base rates means the rates that provide for
the recovery of the utility's costs of generation, transmission, and
distribution services and the return on equity authorized by the Commission,
but does not include revenue recovered by
the utility pursuant to § 56-249.6 or any rate
rider approved for rate adjustment
clauses pursuant to subdivision 4.
5 4. 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, in one combined proceeding per year,
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 former § 56-582 incurred
between July 1, 2004, and the expiration or
termination of capped rates January 1, 2009, 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 former §
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 former § 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.
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 may allow for the recovery of revenue reductions lost net margins from lost sales
related to energy efficiency programs. The Commission shall only may
allow such recovery to the extent that the Commission determines such revenue has lost net margins have 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 4 f. The Commission shall approve such a petition allowing allow 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 4 f 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 4 f 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.; and
6 f.
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,. In
addition, the Commission may authorize an
enhanced rate of return on common equity for the facility,
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 Any enhanced rate of return on common equity authorized by the
Commission pursuant to this subdivision for a facility may not exceed 200
basis points, and, if
awarded, may apply
for a period established by the Commission of
between five and 25 years. The Commission shall determine
whether to authorize an enhanced rate
of return, and the amount and
duration of any enhanced rate of
return so authorized, in order to reflect
any increased risk to the utility caused by the construction of the facility
that is not otherwise reflected in the utility's authorized rate of return on
equity. The approved enhanced
rate of return on common equity shall be added 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. The
Commission, if it is determined to be
in the public interest, may
allow an enhanced rate of return on
common equity shall to
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 for
which an enhanced rate of return has been established by the Commission pursuant to this subdivision 4 f.
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 period for which an authorized
enhanced rate of return for a
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 pursuant
to subdivision 1 c in implementing
any rate of return under this subdivision 4 f. 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 and may include an enhanced
rate of return on common equity as determined pursuant to this subdivision 4 f, 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:
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 4 f,
"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 f, if the Commission finds
during the biennial review conducted for a Phase II utility in 2018 2017 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 4 f.
In order that a utility's retail customers are not subjected to more than one change in rates in any calendar year, except for any revisions to rates authorized by § 56-242, 56-245, or 56-249.6, petitions for rate adjustment clauses under this subdivision 4 shall be combined into single annual proceedings. The Commission shall consider all rate adjustment clause petitions authorized by this subdivision 4 that are filed (a) as part of a single, combined proceeding consolidating all rate adjustment clause proceedings and the biennial review, if the rate adjustment clause petition is filed during the 12 months preceding the filing of the utility's biennial review; or (b) in a single, combined proceeding consolidating all rate adjustment clause proceedings, if the rate adjustment clause petition is filed during the 12 months following the filing of the utility's biennial review.
In each proceeding approving a rate adjustment clause, the Commission shall provide for the establishment of separate accounts for the recovery of approved costs, including any allowed enhanced rate of return on common equity, through a rate adjustment clause that provides for the collection, through current or future utility rates and over the life of the adjustment clause, of the amortized portion of such costs that are determined during the utility's biennial reviews. The Commission shall determine the duration or amortization period for any rate adjustment clause approved under this subdivision 4. The Commission shall also provide for a true-up as part of each biennial review in order that, over the duration of the clause, the utility will recover all of the appropriate costs covered by the clause, including any allowed enhanced return on common equity. The Commission shall adjust the rider rate over the life of the clause, taking into account any changes in costs and excess base rate earnings as provided for in this section, so as to minimize over-collections and under-collections to the extent practicable. If the initial approval of the rate adjustment clause is part of a biennial review, the Commission shall establish a separate rate rider including a rate that provides for the funding of the rate adjustment clause for the next two years, subject to any reduction as a result of excess earnings as provided in this subsection. If the initial approval of the rate adjustment clause is not part of a biennial review, the utility shall provide the necessary information to allow the Commission to determine whether there are any excess earnings for base rates based on the year prior to the filing of the application, and if the Commission determines that there are base rate earnings in excess of the authorized return, the Commission may reduce the rider rate amount by the amount of the excess base rate earnings. In a proceeding in which a rate adjustment clause is approved that is not part of a biennial review, if the excess earnings are sufficient to offset the total rate amount needed until rates established by the next biennial review would be effective, the Commission need not set up a separate rate rider for the clause. In determining the necessary amount of any rate rider during a biennial review, if there is a shortfall for a rate adjustment clause, the Commission shall credit to the account any base rate earnings during the biennial period under review in excess of the authorized return for the period under review up to the amount of the shortfall. If there are one or more such new rate adjustment clauses or there are previously approved rate adjustment clauses that have a shortfall, the Commission shall apportion the excess earnings among the adjustment clauses as it determines is appropriate. The Commission shall not direct that any portion of base rate earnings be credited to any adjustment clauses if such action will reduce the utility’s earned rate of return during the biennial period under review to a level that is less than the fair rate of return on common equity determined pursuant to subdivision 2 for the biennium. If the revenues from a rate rider or overearnings from base rates are not sufficient to satisfy the amount required pursuant to the terms of the rate adjustment clause, the shortfall shall be deferred to future periods and shall be collectible through the rate rider as approved by the Commission as part of a biennial review and true-up. If there are excess revenues collected through a rate rider for a rate adjustment clause, the excess shall be applied to reduce the rate rider for such clause for the next biennial review period as part of the true-up. The Commission shall not approve a rate rider in connection with a rate adjustment clause if it would authorize the utility to charge rates that in the aggregate would provide revenues that exceed the aggregate actual costs incurred by the utility in serving customers within the jurisdiction of the Commission. After such amounts recoverable through rate adjustment clauses are combined, they thereafter shall be considered part of the utility's base rates, as defined in subdivision 3, for the purposes of future biennial review proceedings unless the Commission determines that a separate accounting therefor is appropriate.
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 a rate adjustment
clause 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 4 a,
or that are related to facilities and projects described in clause (i) of
subdivision 6 f, 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 f that utilize nuclear power,
or coal-fueled facilities and projects described in clause (ii) of subdivision 6 f
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 January 1, 2009 related to
other matters described in subdivisions this subdivision 4, 5 or 6
shall be deferred beginning only upon the
expiration or termination of capped rates January 1, 2009, 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 this 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 (1) concurrently
with the Commission's final order in the utility's biennial review if issued
in a year in which a biennial review is conducted for the utility or
(2) not more than nine
months after the filing of all such petitions
in such year are complete if the
petition is filed other than in a year in which a biennial review is conducted
for the utility. If such petition is
approved, the order shall direct that the applicable Any rate
adjustment clause authorized
by this subdivision 4 shall 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 5. If the Commission
determines as a result of such a biennial review that:
(i) a. 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 transmission,
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 base 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;
or
(ii) b. The utility has, during the
test period or test periods under review, considered as a whole, earned more
than 50 basis points above a fair combined rate of return on both its transmission,
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, after deducting the amount
of such excess earnings that are credited to one or more rate adjustment
clauses, 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 to customer's bills 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 shall not direct that any portion of such base
rate earnings be credited to rate
adjustment clauses if such
action will reduce the utility's rate of return to a level that is less than
the fair rate of return on common equity determined pursuant to subdivision 2
for the biennium.
6. The Commission
shall set a utility's rates in a biennial review at a
level that provides the
utility with the opportunity to fully recover its costs of providing its
services, including amounts required
for rate adjustment clauses approved
pursuant to subdivision 4, and
to earn not less than a fair rate of return on its services as determined in
subdivision 2. 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 utility's filing is complete; however, the
Commission may extend such period by an additional period not to exceed nine
months. If the Commission extends the period beyond the initial
nine months, the utility may place a proposed rate increase in effect, subject to refund, at
the end of the nine months after the filing is
complete. 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 7. For purposes of this section, the Commission shall
regulate the rates, terms and conditions of any utility subject to this section
on a stand-alone basis utilizing the actual end-of-test period capital
structure and cost of capital of such utility, 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 upon considering 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. Nothing in this section shall preclude an investor-owned incumbent electric utility
from applying for an a temporary 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.
C. Except as otherwise provided in this section, the
Commission shall exercise authority over the rates, terms and conditions of
investor-owned incumbent
electric utilities for the provision of generation, transmission, and distribution services to
retail customers in the Commonwealth pursuant to the provisions of Chapter 10
(§ 56-232 et seq.) of this title,
including specifically § 56-235.2.
D. 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.
E. 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 increase the fair combined authorize an
increased rate of return on common equity for each renewable energy
generation facility of a
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, which increase in the rate of return on common equity
for the utility's renewable energy generation
facilities is referred to as the "Renewable Incentive."
Such Performance A Renewable Incentive shall
first be used in the calculation of a fair combined
rate of return for such a facility 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 and the facility continues to be owned and operated
by the utility 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 goals
for energy derived from sunlight or from onshore wind, and triple credit toward
meeting the renewable energy portfolio standard goals
for energy derived from offshore wind.
D. To qualify for the Performance a Renewable
Incentive established 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, subject to Commission approval,
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 subdivision A 5 4 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 4 f 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 4 f of §
56-585.1. 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 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. A participating utility may sell
renewable energy certificates produced at its own generation facilities located
in the Commonwealth or, if located outside the Commonwealth, owned by such
utility and in operation as of January 1, 2010, or renewable energy
certificates acquired as part of a purchase power agreement, to another entity
and purchase lower cost renewable energy certificates and the net difference in
price between the renewable energy certificates shall be credited to customers.
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 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 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 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.
A. After the expiration or termination of capped rates, the rates, terms and conditions of distribution electric cooperatives subject to Article 1 (§ 56-231.15 et seq.) of Chapter 9.1 of this title shall be regulated in accordance with the provisions of Chapters 9.1 (§ 56-231.15 et seq.) and 10 (§ 56-232 et seq.) of this title, as modified by the following provisions:
1. Except for energy related cost (fuel cost), the Commission shall not require any cooperative to adjust, modify, or revise its rates, by means of riders or otherwise, to reflect changes in wholesale power cost which occurred during the capped rate period, other than in a general rate proceeding;
2. Each cooperative may, without Commission approval or the requirement of any filing other than as provided in this subdivision, upon an affirmative resolution of its board of directors, increase or decrease all classes of its rates for distribution services at any time, provided, however, that such adjustments will not effect a cumulative net increase or decrease in excess of 5 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. Each cooperative may, without Commission approval or the requirement of any filing other than as provided in this subdivision, upon an affirmative resolution of its board of directors, make any adjustment to its rates reasonably calculated to collect any or all of the fixed costs of owning and operating its electric distribution system, including without limitation, such costs as are identified as customer-related costs in a cost of service study, through a new or modified fixed monthly charge, rather than through volumetric charges associated with the use of electric energy; however, such adjustments shall be revenue neutral based on the cooperative's determination of the proper intra-class allocation of the revenues produced by its then current rates. The cooperative may elect, but is not required, to implement such adjustments through incremental changes over the course of up to three years. The cooperative shall file promptly revised tariffs reflecting any such adjustments with the Commission for informational purposes; and
5. A cooperative may, at any time after the
expiration or termination of capped rates January 1, 2009, 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 4
b and e of § 56-585.1.
B. None of the adjustments described in subdivisions A 2 through A 5 will apply to the rates paid by any customer that takes service by means of dedicated distribution facilities and had noncoincident peak demand in excess of 90 megawatts in calendar year 2006.
C. Nothing in this section shall be deemed to grant to a cooperative any authority to amend or adjust any terms and conditions of service or agreements regarding pole attachments or the use of the cooperative's poles or conduits.
§ 56-590. Divestiture, functional separation and other corporate relationships.
A. The
Commission shall not require any incumbent
electric utility to divest itself of any generation, transmission, or distribution assets, or to separate its generation, transmission, and
distribution functions, pursuant to any provision of this
chapter.
B. 1. The Commission
shall, however, direct the functional separation of generation, retail
transmission and distribution of all incumbent electric utilities in connection
with the provisions of this chapter to be completed by January 1, 2002.
2. By January 1, 2001,
each incumbent electric utility shall submit to the Commission a plan for such
functional separation which may be accomplished through the creation of
affiliates, or through such other means as may be acceptable to the Commission.
3. Consistent with
this chapter, the Commission may impose conditions, as the public interest
requires, upon its approval of any incumbent electric utility's plan for
functional separation, including requirements that (i) the incumbent electric
utility's generation assets or, at the election of the incumbent electric
utility and if approved by the Commission pursuant to subdivision 4 of this
subsection, their equivalent are made available for electric service during the
capped rate period as provided in § 56-582 and, if applicable, during any
period the distributor serves as a default provider as provided for in §
56-585; (ii) the incumbent electric utility receive Commission approval for the
sale, transfer or other disposition of generation assets during the capped rate
period and, if applicable, during any period the distributor serves as a
default provider; and (iii) any such generation asset sold, transferred, or
otherwise disposed of by the incumbent electric utility with Commission
approval shall not be further sold, transferred, or otherwise disposed of
during the capped rate period and, if applicable, during any period the
distributor serves as default provider, without additional Commission approval.
4. If an incumbent electric
utility proposes that the equivalent to its generation assets be made available
pursuant to subdivision 3 of this subsection, the Commission shall determine
the adequacy of such proposal and shall approve or reject such proposal based
on the public interest.
5. In exercising its
authority under the provisions of this section and under § 56-90, the
Commission shall have no authority to regulate, on a cost-of-service basis or
other basis, the price at which generation assets or their equivalent are made
available for default service purposes. Such restriction on the Commission's
authority to regulate, on a cost-of-service basis or other basis, prices for
default service shall not affect the ability of a distributor to offer to
provide, and of the Commission to approve if appropriate the provision of, such
services on a cost plus basis or any other basis. The Commission's authority to
regulate the price of default service shall be consistent with the pricing
provisions applicable to a distributor pursuant to § 56-585. In addition, the
Commission shall, in exercising its responsibilities under this section and
under § 56-90, consider, among other factors, the potential effects of any such
transfer on: (i) rates and reliability of capped rate service under § 56-582,
and of default service under § 56-585, and (ii) the development of a
competitive market in the Commonwealth for retail generation services. However,
the Commission may not deny approval of a transfer proposed by an incumbent
electric utility, pursuant to subdivisions 2 and 4 of subsection B, due to an
inability to determine, at the time of consideration of the transfer, default
service prices under § 56-585.
C. The Commission
shall, to the extent necessary to promote effective competition in the
Commonwealth, promulgate rules and regulations to carry out the provisions of
this section, which rules and regulations shall include provisions:
1. Prohibiting
cost-shifting or cross-subsidies between functionally separate units;
2. Prohibiting functionally
separate units from engaging in anticompetitive behavior or self-dealing;
3. Prohibiting
affiliated entities from engaging in discriminatory behavior towards
nonaffiliated units; and
4. Establishing codes
of conduct detailing permissible relations between functionally separate units.
D. Neither a covered
entity nor an affiliate thereof may be a party to a covered transaction without
the prior approval of the Commission. Any such person proposing to be a party
to such transaction shall file an application with the Commission. The
Commission shall approve or disapprove such transaction within sixty days after
the filing of a completed application; however, the sixty-day period may be
extended by Commission order for a period not to exceed an additional 120 days.
The application shall be deemed approved if the Commission fails to act within
such initial or extended period. The Commission shall approve such application
if it finds, after notice and opportunity for hearing, that the transaction
will comply with the requirements of subsection E, and may, as a part of its
approval, establish such conditions or limitations on such transaction as it
finds necessary to ensure compliance with subsection E.
E. A transaction
described in subsection D shall not:
1. Substantially
lessen competition among the actual or prospective providers of noncompetitive
electric service or of a service which is, or is likely to become, a
competitive electric service; or
2. Jeopardize or
impair the safety or reliability of electric service in the Commonwealth, or
the provision of any noncompetitive electric service at just and reasonable
rates.
F. Except as provided
in subdivision B 5, nothing in this chapter shall be deemed to abrogate or
modify the Commission's authority under Chapter 3 (§ 56-55 et seq.), 4 (§ 56-76
et seq.) or 5 (§ 56-88 et seq.) of this title. However, any person subject to
the requirements of subsection D that is also subject to the requirements of
Chapter 5 of this title may be exempted from compliance with the requirements
of Chapter 5 of this title.
§ 56-592. Consumer education and marketing practices.
A. The Commission shall develop an electric energy consumer education program designed to provide the following information to retail customers:
1. Information regarding energy conservation, energy efficiency, demand-side management, demand response, and renewable energy;
2. Information concerning demand-side management and demand response programs offered in the Commonwealth to retail customers;
3. Information regarding the matters described in subdivisions 1 and 2 that are specifically designed for the industrial, commercial, residential, and government sectors; and
4. Such other information as the Commission may deem necessary and appropriate in the public interest.
B. The Commission shall complete the development of the consumer education program described in subsection A, and report its findings and recommendations to the Commission on Electric Utility Regulation as frequently as may be required by such Commission concerning:
1. The scope of such recommended program consistent with the requirements of subsection A;
2. Materials and media required to effectuate any such program;
3. State agency and nongovernmental entity participation;
4. Program duration;
5. Funding requirements and mechanisms for any such program; and
6. Such other findings and recommendations the Commission deems appropriate in the public interest.
C. The Commission shall develop regulations governing
marketing practices by public service companies,
licensed suppliers, aggregators or any other providers of services made
competitive by this chapter, including regulations to
prevent unauthorized switching of suppliers,
unauthorized charges,
and improper solicitation activities. The Commission shall
also establish standards for marketing information to be furnished by licensed
suppliers, aggregators or any other providers of services made competitive by
this chapter, which information shall include standards concerning:
1. Pricing and other
key contract terms and conditions;
2. To the extent
feasible, fuel mix and emissions data on at least an annualized basis;
3. Customer's rights
of cancellation following execution of any contract;
4. Toll-free telephone
number for customer assistance; and
5. Such other and
further marketing information as the Commission may deem necessary and
appropriate in the public interest.
D. The Commission shall
also establish standards for billing information to be furnished by public
service companies, suppliers, aggregators or any other providers of services
made competitive by this chapter. Such billing information standards shall
require that billing formation:
1. Distinguishes
between charges for regulated services and unregulated services;
2. Is presented in a
format that complies with standards to be established by the Commission;
3. Discloses, to the
extent feasible, fuel mix and emissions data on at least an annualized basis;
and
4. Includes such other
billing information as the Commission deems necessary and appropriate in the
public interest.
E.
The Commission shall establish or maintain a complaint bureau for the purpose
of receiving, reviewing and investigating complaints by retail customers
against public service companies, licensed suppliers,
aggregators and other providers of any services made competitive under this
chapter. Upon the request of any interested person or the
Attorney General, or upon its own motion, the Commission shall be authorized to
inquire into possible violations of this chapter and to enjoin or punish any
violations thereof pursuant to its authority under this chapter, this title,
and under Title 12.1. The Attorney General shall have a right to participate in
such proceedings consistent with the Commission's Rules of Practice and
Procedure.
FE. The Commission shall
establish reasonable limits on customer security deposits required by public
service companies, suppliers,
aggregators or any other persons providing competitive services pursuant to
this chapter.
§ 56-593. Retail customers' private right of action; marketing practices.
A. No entity subject to this chapter shall use any deception, fraud, false pretense, misrepresentation, or any deceptive or unfair practices in providing, distributing or marketing electric service.
B. 1. Any person who suffers loss
(i) as the result of marketing practices, including telemarketing practices,
engaged in by any public service company, licensed supplier,
aggregator or any other provider of any service made competitive under this
chapter, and in violation of subsection C of § 56-592,
including any rule or regulation adopted by the Commission pursuant thereto, or
(ii) as the result of any violation of subsection A, shall be entitled to
initiate an action to recover actual damages, or $500, whichever is greater. If
the trier of fact finds that the violation was willful, it may increase damages
to an amount not exceeding three times the actual damages sustained, or $1,000,
whichever is greater.
2. Upon referral from the Commission, the Attorney General, the attorney for the Commonwealth, or the attorney for any city, county, or town may cause an action to be brought in the appropriate circuit court for relief of violations within the scope of (i) subsection C of § 56-592, including any rule or regulation adopted by the Commission pursuant thereto or (ii) subsection A.
C. Notwithstanding any other provision of law to the contrary, in addition to any damages awarded, such person, or any governmental agency initiating such action, also may be awarded reasonable attorney's fees and court costs.
D. Any action pursuant to this section shall be commenced within two years after its accrual. The cause of action shall accrue as provided in § 8.01-230. However, if the Commission initiates proceedings, or any other governmental agency files suit for the purpose of enforcing subsection A of this section or the provisions of subsection C of § 56-592, the time during which such proceeding or governmental suit and all appeals therefrom is pending shall not be counted as any part of the period within which an action under this section shall be brought.
E. The circuit court may make such additional orders or decrees as may be necessary to restore to any identifiable person any money or property, real, personal, or mixed, tangible or intangible, which may have been acquired from such person by means of any act or practice violative of subsection A of this section or subsection C of § 56-592, provided, that such person shall be identified by order of the court within 180 days from the date of any order permanently enjoining the unlawful act or practice.
F. In any case arising under this section, no liability shall
be imposed upon any licensed supplier,
aggregator or any other provider of any service made competitive under this
chapter, who public service
company that shows by a preponderance of the evidence that
(i) the act or practice alleged to be in violation of subsection A of this
section or subsection C of § 56-592 was an act or practice over which the same
had no control or (ii) the alleged violation resulted from a bona fide error
notwithstanding the maintenance of procedures reasonably adopted to avoid a
violation. However, nothing in this section shall prevent the court from
ordering restitution and payment of reasonable attorney's fees and court costs
pursuant to subsection C to individuals aggrieved as a result of an
unintentional violation of subsection A of this section or subsection C of §
56-592.
§ 56-594. Net energy metering provisions.
A. The Commission shall establish by regulation a program, to begin no later than July 1, 2000, that affords eligible customer-generators the opportunity to participate in net energy metering. The regulations may include, but need not be limited to, requirements for (i) retail sellers; (ii) owners and/or operators of distribution or transmission facilities; (iii) providers of default service; (iv) eligible customer-generators; or (v) any combination of the foregoing, as the Commission determines will facilitate the provision of net energy metering, provided that the Commission determines that such requirements do not adversely affect the public interest.
B. For the purpose of this section:
"Eligible customer-generator" means a customer that
owns and operates, or contracts with other persons to own, operate, or both, an
electrical generating facility that (i) has a capacity of not more than 10
kilowatts for residential customers and 500 kilowatts for nonresidential
customers unless a utility elects a higher capacity limit for such a facility;
(ii) uses as its total source of fuel renewable energy, as defined in § 56-576;
(iii) is located on the customer's premises and is connected to the customer's
wiring on the customer's side of its interconnection with the distributor electric utility; (iv) is
interconnected and operated in parallel with an electric company's utility's
transmission and distribution facilities; and (v) is intended primarily to
offset all or part of the customer's own electricity requirements.
"Net energy metering" means measuring the difference, over the net metering period, between (i) electricity supplied to an eligible customer-generator from the electric grid and (ii) the electricity generated and fed back to the electric grid by the eligible customer-generator.
"Net metering period" means the 12-month period following the date of final interconnection of the eligible customer-generator's system with an electric service provider, and each 12-month period thereafter.
C. The Commission's regulations shall ensure that the metering equipment installed for net metering shall be capable of measuring the flow of electricity in two directions, and shall allocate fairly the cost of such equipment and any necessary interconnection. An eligible customer-generator's electrical generating system shall meet all applicable safety and performance standards established by the National Electrical Code, the Institute of Electrical and Electronics Engineers, and accredited testing laboratories such as Underwriters Laboratories. Beyond the requirements set forth in this section, an eligible customer-generator whose electrical generating system meets those standards and rules shall bear the reasonable cost, if any, as determined by the Commission, to (i) install additional controls, (ii) perform or pay for additional tests, or (iii) purchase additional liability insurance.
D. The Commission shall establish minimum requirements for contracts to be entered into by the parties to net metering arrangements. Such requirements shall protect the customer-generator against discrimination by virtue of its status as a customer-generator, and permit customers that are served on time-of-use tariffs that have electricity supply demand charges contained within the electricity supply portion of the time-of-use tariffs to participate as an eligible customer-generator. Notwithstanding the cost allocation provisions of subsection C, eligible customer-generators served on demand charge-based time-of-use tariffs shall bear the incremental metering costs required to net meter such customers.
E. If electricity generated by an eligible customer-generator
over the net metering period exceeds the electricity consumed by the
customer-generator, the customer-generator shall be compensated for the excess
electricity if the entity contracting to receive such electric energy and the
customer-generator enter into a power purchase agreement for such excess
electricity. Upon the written request of the customer-generator, the supplier electric utility that serves the eligible
customer-generator shall enter into a power purchase agreement with the
requesting eligible customer-generator that is consistent with the minimum requirements
for contracts established by the Commission pursuant to subsection D. The power
purchase agreement shall obligate the supplier electric utility to purchase
such excess electricity at the rate that is provided for such purchases in a
net metering standard contract or tariff approved by the Commission, unless the
parties agree to a higher rate. The eligible customer-generator owns the
renewable energy certificates associated with its electrical generating
facility, however, at the time that the eligible customer-generator enters into
a power purchase agreement with its supplier electric utility, the
customer-generator shall have a one-time option to sell the renewable energy
certificates associated with such electrical generating facility to its supplier electric utility and be compensated at an amount that is
established by the Commission to reflect the value of such renewable energy
certificates. Nothing in this section shall prevent the eligible
customer-generator and the supplier electric utility from
voluntarily entering into an agreement for the sale and purchase of excess
electricity or renewable energy certificates at mutually-agreed upon prices if
the eligible customer-generator does not exercise its option to sell its
renewable energy certificates to its supplier electric utility at
Commission-approved prices at the time that the eligible customer-generator
enters into a power purchase agreement with its supplier electric utility.
All costs incurred by the supplier to purchase excess electricity and renewable
energy certificates from eligible customer-generators shall be recoverable
through its Renewable Energy Portfolio Standard (RPS) rate adjustment clause,
if the supplier electric utility has a
Commission-approved RPS plan. If not, then all costs shall be recoverable
through the supplier's electric utility's fuel
adjustment clause. For purposes of this section, "all costs" shall be
defined as the rates paid to the eligible customer-generator for the purchase
of excess electricity and renewable energy certificates and any administrative
costs incurred to manage the eligible customer-generator's power purchase
arrangements. The net metering standard contract or tariff shall be available
to eligible customer-generators on a first-come, first-served basis in each
electric distribution company's Virginia service area until the rated
generating capacity owned and operated by eligible customer-generators in the
state reaches one percent of each electric distribution company's adjusted
Virginia peak-load forecast for the previous year, and shall require the supplier electric utility to pay the eligible customer-generator for
such excess electricity in a timely manner at a rate to be established by the
Commission.
§ 58.1-400.3. Minimum tax on certain electric suppliers.
A. 1. An electric supplier, except for those organized as cooperatives and exempt from federal taxation under § 501 of the Internal Revenue Code of 1986, as amended, shall be subject to a minimum tax imposed by this section, instead of the corporate income tax imposed by § 58.1-400 if applicable, net of any income tax credits that may be used to offset such tax, if the tax imposed by § 58.1-400 is less than the minimum tax imposed by this subsection. An electric supplier that is organized as a limited liability, partnership, corporation that has made an election under subchapter S of the Internal Revenue Code, or other entity treated as a pass-through entity shall be subject to the minimum tax in the manner prescribed by regulation.
2. The minimum tax imposed by this subsection shall be equal to 1.45 percent of such electric supplier's gross receipts for the calendar year that ends during the taxable year minus the state's portion of the electric utility consumption tax billed to consumers.
B. 1. An electric supplier that is organized as a cooperative and exempt from federal taxation under § 501 of the Internal Revenue Code of 1986, as amended, shall be subject to a minimum tax, instead of the tax on modified net income imposed by § 58.1-400.2, if the tax imposed by § 58.1-400.2, net of any credits that may be used to offset such tax, is less than the minimum tax imposed by this subsection.
2. The minimum tax imposed by this subsection shall be equal to 1.45 percent of such electric supplier's gross receipts from sales to nonmembers for the calendar year that ends during the taxable year minus the consumption tax collected from nonmembers.
C. In the case of an income tax return for a period of less than 12 months, the minimum tax shall be based on the gross receipts for the calendar year that ends during the taxable period or, if none, the most recent calendar year that ended before the taxable period. The minimum tax shall be prorated by the number of months in the taxable period.
D. The State Corporation Commission shall calculate and certify to the Department for each tax year as defined in § 58.1-2600 the name, address, and minimum tax for each electric supplier. The Commission shall mail or otherwise deliver a copy of the certification to each affected electric supplier.
E. When an electric supplier subject to the tax imposed by this section is one of several affiliated corporations that file a consolidated or combined income tax return, the portion of the affiliated corporations' tax liability that is attributable to the electric supplier shall be computed as follows:
1. Each corporation included in the consolidated or combined return shall recompute its corporate income tax liability, net of any income tax credits, as if it were filing a separate return. The separate income tax liability of the electric supplier shall then be compared to the affiliated corporations' tax liability, net of any income tax credits, indicated on the consolidated or combined return. For purposes of this section, the lesser amount shall be deemed to be the corporate income tax imposed by § 58.1-400 and attributable to the electric supplier.
2. a. If such corporate income tax amount is less than the minimum tax of the electric supplier as calculated pursuant to subsection A, the electric supplier shall be subject to the minimum tax in lieu of the corporate income tax imposed by § 58.1-400.
b. If such corporate income tax amount exceeds the minimum tax of the electric supplier as calculated pursuant to subsection A, the electric supplier shall not owe the minimum tax.
F. The requirements imposed under Article 20 (§ 58.1-500 et seq.) of Chapter 3 of this title regarding the filing of a declaration of estimated income taxes and the payment of such estimated taxes, shall be applicable to electric suppliers regardless of whether such taxpayer expects to be subject to the minimum tax imposed herein or to the corporate income tax imposed by § 58.1-400.
For purposes of determining the applicability of the exceptions under which the addition to the tax for the underpayment of any installment of estimated taxes shall not be imposed, it shall be irrelevant whether the tax shown on the return for the preceding taxable year is the corporate income tax or the minimum tax.
G. To the extent that a taxpayer is subject to the minimum tax imposed under this section, there shall be allowed a credit against the separate, combined, or consolidated corporate income tax for the total amount of minimum tax paid by the electric supplier in all previous years that is in excess of the tax imposed by § 58.1-400 on the electric supplier for such years.
H. 1. To the extent an electric supplier or its parent company has remitted estimated income tax payments in excess of its corporate income tax liability for the taxable years beginning on or after January 1, 2001, but before January 1, 2004, such overpayments shall only be utilized to offset any corporate income tax liabilities incurred pursuant to § 58.1-400 for taxable years beginning on and after January 1, 2004, and shall not be claimed as a refund of overpaid taxes, except as provided in subdivision 2 of this subsection. For the purposes of this subsection, estimated income tax payments shall include any overpayments from a prior taxable year carried forward as an estimated payment to be credited towards a future tax liability.
2. If an electric supplier has had a corporate income tax liability of greater than $0 for each taxable year beginning on or after January 1, 2001, but before January 1, 2003, then such electric supplier may claim a refund of any estimated income tax payments in excess of their taxable year 2003 corporate income tax liability.
I. Every electric supplier which owes the minimum tax imposed by this section shall remit such tax payment to the Department of Taxation.
J. Notwithstanding any
of the foregoing provisions, an electric supplier may not adjust capped rates
pursuant to § 56-582 of the Code of Virginia on any portion of the minimum tax
due to the Commonwealth.
K.
The following words and terms, for purposes of this section, shall have the
following meanings:
"Consumption tax" means the state's portion of the electric utility consumption tax billed pursuant to Chapter 29 (§ 58.1-2900 et seq.) of this title, for which the electric supplier is defined as the "service provider" pursuant to § 58.1-2901 less any amounts billed on behalf of utilities owned and operated by municipalities.
"Electric supplier" means an incumbent electric utility in the Commonwealth that, prior to July 1, 1999, supplied electric energy to retail customers located in an exclusive service territory established by the State Corporation Commission.
"Gross receipts" has the same meaning as defined in § 58.1-2600 less receipts from sales to federal, state and local governments for their own use.
"Nonmember" has the same meaning as defined in § 58.1-400.2.
2. That any rate adjustment clauses approved by the State Corporation Commission, prior to the effective date of this act, in a proceeding instituted pursuant to subdivision A 5 or A 6 of § 56-585.1 of the Code of Virginia as it existed prior to the effective date of this act, shall continue in effect on the terms and conditions set forth in the of the order approving them, subject to the following: (i) revenue collected by an investor-owned electric utility pursuant to a rate adjustment clause shall be considered by the State Corporation Commission in determining the utility's total revenue and rate of return on equity in any ratemaking proceeding under Title 56; (ii) the utility shall continue to be authorized to collect any enhanced rate of return on equity above the approved general rate of return on equity or margin on operating expenses that was approved by the State Corporation Commission in any such proceeding, which authorization shall not prevent the Commission from adjusting the utility's general rate of return on equity in any subsequent biennial review conducted under § 56-585.1; (iii) the duration of any enhanced rate of return on common equity for a generation facility that was approved by the State Corporation Commission pursuant to subdivision A 6 of § 56-585.1 shall not be shortened by subsequent order of the Commission; and (iv) any such rate adjustment clause shall continue to be accounted for separately for its approved duration.
3. That §§ 56-577, 56-582, 56-584, 56-585, 56-586, 56-587, 56-588, and 56-589 of the Code of Virginia are repealed.