Be it enacted by the General Assembly of Virginia:
1. That §§ 56-265.1, 56-576, 56-585.1, and 56-585.1:1 of the Code of Virginia are amended and reenacted as follows:
§56-265.1. Definitions.
In this chapter the following terms shall have the following meanings:
(a) "Company" means a corporation, a limited liability company, an individual, a partnership, an association, a joint-stock company, a business trust, a cooperative, or an organized group of persons, whether incorporated or not; or any receiver, trustee or other liquidating agent of any of the foregoing in his capacity as such; but not a municipal corporation or a county, unless such municipal corporation or county has obtained a certificate pursuant to §56-265.4:4.
(b) "Public utility" means any company which
that owns or operates facilities
within the Commonwealth of Virginia for the generation, transmission,
storage or distribution of electric energy for sale, for the
production, storage, transmission, or distribution, otherwise than in enclosed
portable containers, of natural or manufactured gas or geothermal resources for
sale for heat, light or power, or for the furnishing of telephone service,
sewerage facilities or water; however,
As used in this definition, a facility for the storage of electric energy for
sale includes one or more pumped hydroelectricity generation and storage
facilities located in the coalfield region of Virginia as described in §
15.2-6002. However, the term "public utility" shall
does not include any of the following:
(1) Except as otherwise provided in §56-265.3:1, any company furnishing sewerage facilities, geothermal resources or water to less than 50 customers. Any company furnishing water or sewer services to 10 or more customers and excluded by this subdivision from the definition of "public utility" for purposes of this chapter nevertheless shall not abandon the water or sewer services unless and until approval is granted by the Commission or all the customers receiving such services agree to accept ownership of the company.
(2) Any company generating and distributing electric energy exclusively for its own consumption.
(3) Any company (A) which furnishes electric service together
with heating and cooling services, generated at a central plant installed on
the premises to be served, to the tenants of a building or buildings located on
a single tract of land undivided by any publicly maintained highway, street or
road at the time of installation of the central plant, and (B) which does not
charge separately or by meter for electric energy used by any tenant except as
part of a rental charge. Any company excluded by this subdivision from the
definition of "public utility" for the purposes of this chapter
nevertheless shall, within 30 days following the issuance of a building permit,
notify the State Corporation Commission in writing of the ownership, capacity
and location of such central plant, and it shall be subject, with regard to the
quality of electric service furnished, to the provisions of Chapters 10 (§
56-232 et seq.) and 17 (§56-509 et seq.) of this title and
regulations thereunder and be deemed a public utility for such purposes, if
such company furnishes such service to 100 or more lessees.
(4) Any company, or affiliate thereof, making a first or direct sale, or ancillary transmission or delivery service, of natural or manufactured gas to fewer than 35 commercial or industrial customers, which are not themselves "public utilities" as defined in this chapter, or to certain public schools as indicated in this subdivision, for use solely by such purchasing customers at facilities which are not located in a territory for which a certificate to provide gas service has been issued by the Commission under this chapter and which, at the time of the Commission's receipt of the notice provided under §56-265.4:5, are not located within any area, territory, or jurisdiction served by a municipal corporation that provided gas distribution service as of January 1, 1992, provided that such company shall comply with the provisions of §56-265.4:5. Direct sales or ancillary transmission or delivery services of natural gas to public schools in the following localities may be made without regard to the number of schools involved and shall not count against the "fewer than 35" requirement in this subdivision: the Counties of Dickenson, Wise, Russell, and Buchanan, and the City of Norton.
(5) Any company which is not a public service corporation and which provides compressed natural gas service at retail for the public.
(6) Any company selling landfill gas from a solid waste management facility permitted by the Department of Environmental Quality to a public utility certificated by the Commission to provide gas distribution service to the public in the area in which the solid waste management facility is located. If such company submits to the public utility a written offer for sale of such gas and the public utility does not agree within 60 days to purchase such gas on mutually satisfactory terms, then the company may sell such gas to (i) any facility owned and operated by the Commonwealth which is located within three miles of the solid waste management facility or (ii) any purchaser after such landfill gas has been liquefied. The provisions of this subdivision shall not apply to the City of Lynchburg or Fairfax County.
(7) Any authority created pursuant to the Virginia Water and Waste Authorities Act (§15.2-5100 et seq.) making a sale or ancillary transmission or delivery service of landfill gas to a commercial or industrial customer from a solid waste management facility permitted by the Department of Environmental Quality and operated by that same authority, if such an authority limits off-premises sale, transmission or delivery service of landfill gas to no more than one purchaser. The authority may contract with other persons for the construction and operation of facilities necessary or convenient to the sale, transmission or delivery of landfill gas, and no such person shall be deemed a public utility solely by reason of its construction or operation of such facilities. If the purchaser of the landfill gas is located within the certificated service territory of a natural gas public utility, the public utility may file for Commission approval a proposed tariff to reflect any anticipated or known changes in service to the purchaser as a result of the use of landfill gas. No such tariff shall impose on the purchaser of the landfill gas terms less favorable than similarly situated customers with alternative fuel capabilities; provided, however, that such tariff may impose such requirements as are reasonably calculated to recover the cost of such service and to protect and ensure the safety and integrity of the public utility's facilities.
(8) A company selling or delivering only landfill gas, electricity generated from only landfill gas, or both, that is derived from a solid waste management facility permitted by the Department of Environmental Quality and sold or delivered from any such facility to not more than three commercial or industrial purchasers or to a natural gas or electric public utility, municipal corporation or county as authorized by this section. If a purchaser of the landfill gas is located within the certificated service territory of a natural gas public utility or within an area in which a municipal corporation provides gas distribution service and the landfill gas is to be used in facilities constructed after January 1, 2000, such company shall submit to such public utility or municipal corporation a written offer for sale of that gas prior to offering the gas for sale or delivery to a commercial or industrial purchaser. If the public utility or municipal corporation does not agree within 60 days following the date of the offer to purchase such landfill gas on mutually satisfactory terms, then the company shall be authorized to sell such landfill gas, electricity, or both, to the commercial or industrial purchaser, utility, municipal corporation, or county. Such public utility may file for Commission approval a proposed tariff to reflect any anticipated or known changes in service to the purchaser as a result of the purchaser's use of the landfill gas. No such tariff shall impose on such purchaser of the landfill gas terms less favorable than those imposed on similarly situated customers with alternative fuel capabilities; provided, however, that such tariff may impose such requirements as are reasonably calculated to recover any cost of such service and to protect and ensure the safety and integrity of the public utility's facilities.
(9) A company that is not organized as a public service company pursuant to subsection D of §13.1-620 and that sells and delivers propane air only to one or more public utilities. Any company excluded by this subdivision from the definition of "public utility" for the purposes of this chapter nevertheless shall be subject to the Commission's jurisdiction relating to gas pipeline safety and enforcement.
(10) A farm or aggregation of farms that owns and operates facilities within the Commonwealth for the generation of electric energy from waste-to-energy technology. As used in this subdivision, (i) "farm" means any person that obtains at least 51 percent of its annual gross income from agricultural operations and produces the agricultural waste used as feedstock for the waste-to-energy technology, (ii) "agricultural waste" means biomass waste materials capable of decomposition that are produced from the raising of plants and animals during agricultural operations, including animal manures, bedding, plant stalks, hulls, and vegetable matter, and (iii) "waste-to-energy technology" means any technology, including but not limited to a methane digester, that converts agricultural waste into gas, steam, or heat that is used to generate electricity on-site.
(11) A company, other than an entity organized as a public service company, that provides non-utility gas service as provided in § 56-265.4:6.
(12) A company, other than an entity organized as a public service company, that provides storage of electric energy that is not for sale to the public.
(c) "Commission" means the State Corporation Commission.
(d) "Geothermal resources" means those resources as defined in §45.1-179.2.
§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.).
"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 distribution grid transformation project" means a project associated with electric distribution infrastructure, including related data analytics equipment, that is designed to accommodate or facilitate the integration of utility-owned or customer-owned renewable electric generation resources with the utility's electric distribution grid or to otherwise enhance electric distribution grid reliability, electric distribution grid security, customer service or energy efficiency and conservation, including advanced metering infrastructure, intelligent grid devices for real time system and asset information, automated control systems for electric distribution circuits and substations, communications networks for service meters, intelligent grid devices and other distribution equipment, distribution system hardening projects for circuits and substations designed to reduce service outages or service restoration times, physical security measures at key distribution substations, cyber security measures, energy storage systems and microgrids that support circuit-level grid stability, power quality, reliability or resiliency or provide temporary backup energy supply, electrical facilities and infrastructure necessary to support electric vehicle charging systems, LED street light conversions, and new customer information platforms designed to provide improved customer access, greater service options and expanded access to energy usage information.
"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, 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; (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; and (iii) customer engagement programs that result in measurable and verifiable energy savings that lead to efficient use patterns and practices. 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.
"In the public interest," for purposes of assessing
energy efficiency programs, describes an energy efficiency program if,
among other factors, the net present value of the benefits exceeds
the net present value of the costs as determined by not less than any
three the Commission upon consideration of
the following four benefit cost tests: (i) the Total
Resource Cost Test; (ii) the Utility Cost Test (also referred to as the Program
Administrator Test); (iii) the Participant Test; and (iv) the Ratepayer Impact
Measure Test. Such determination shall include an analysis of all
four tests, and a program or portfolio of programs shall not be rejected based
solely on the results of a single test. In addition, an energy
efficiency program may be deemed to be "in the public interest" if
the program provides measurable and verifiable energy savings to low-income
customers or elderly customers.
"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.
"New underground facilities" means facilities to provide underground distribution service. "New underground facilities" includes underground cables with voltages of 69 kilovolts or less, pad-mounted devices, connections at customer meters, and transition terminations from existing overhead distribution sources.
"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, landfill gas, 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.
"Renewable thermal energy" means the thermal energy output from (i) a renewable-fueled combined heat and power generation facility that is (a) constructed, or renovated and improved, after January 1, 2012, (b) located in the Commonwealth, and (c) utilized in industrial processes other than the combined heat and power generation facility or (ii) a solar energy system, certified to the OG-100 standard of the Solar Ratings and Certification Corporation or an equivalent certification body, that (a) is constructed, or renovated and improved, after January 1, 2013, (b) is located in the Commonwealth, and (c) heats water or air for residential, commercial, institutional, or industrial purposes.
"Renewable thermal energy equivalent" means the electrical equivalent in megawatt hours of renewable thermal energy calculated by dividing (i) the heat content, measured in British thermal units (BTUs), of the renewable thermal energy at the point of transfer to a residential, commercial, institutional, or industrial process by (ii) the standard conversion factor of 3.413 million BTUs per megawatt hour.
"Renovated and improved facility" means a facility the components of which have been upgraded to enhance its operating efficiency.
"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.
"Rooftop solar installation" means a distributed electric generation facility, storage facility, or generation and storage facility utilizing energy derived from sunlight, with a rated capacity of not less than 50 kilowatts, that is installed on the roof structure of an incumbent electric utility's commercial or industrial class customer, including host sites on commercial buildings, multi-family residential buildings, school or university buildings, and buildings of a church or religious body.
"Solar energy system" means a system of components that produces heat or electricity, or both, from sunlight.
"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.
§56-585.1. Generation, distribution, and transmission rates after capped rates terminate or expire.
A. During the first six months of 2009, the Commission shall,
after notice and opportunity for hearing, initiate proceedings to review the
rates, terms and conditions for the provision of generation, distribution and
transmission services of each investor-owned incumbent electric utility. Such
proceedings shall be governed by the provisions of Chapter 10 (§56-232 et
seq.), except as modified herein. In such proceedings the Commission shall
determine fair rates of return on common equity applicable to the generation
and distribution services of the utility. In so doing, the Commission may use
any methodology to determine such return it finds consistent with the public
interest, but such return shall not be set lower than the average of the
returns on common equity reported to the Securities and Exchange Commission for
the three most recent annual periods for which such data are available by not
less than a majority, selected by the Commission as specified in subdivision 2
b, of other investor-owned electric utilities in the peer group of the utility,
nor shall the Commission set such return more than 300 basis points higher than
such average. The peer group of the utility shall be determined in the manner
prescribed in subdivision 2 b. The Commission may increase or decrease such
combined rate of return by up to 100 basis points based on the generating plant
performance, customer service, and operating efficiency of a utility, as
compared to nationally recognized standards determined by the Commission to be
appropriate for such purposes. In such a proceeding, the Commission shall
determine the rates that the utility may charge until such rates are adjusted.
If the Commission finds that the utility's combined rate of return on common
equity is more than 50 basis points below the combined rate of return as so
determined, it shall be authorized to order increases to the utility's rates
necessary to provide the opportunity to fully recover the costs of providing
the utility's services and to earn not less than such combined rate of return.
If the Commission finds that the utility's combined rate of return on common
equity is more than 50 basis points above the combined rate of return as so
determined, it shall be authorized either (i) to order reductions to the utility's
rates it finds appropriate, provided that the Commission may not order such
rate reduction unless it finds that the resulting rates will provide the
utility with the opportunity to fully recover its costs of providing its
services and to earn not less than the fair rates of return on common equity
applicable to the generation and distribution services; or (ii) to direct that
60 percent of the amount of the utility's earnings that were more than 50 basis
points above the fair combined rate of return for calendar year 2008 be
credited to customers' bills, in which event such credits shall be amortized
over a period of six to 12 months, as determined at the discretion of the
Commission, following the effective date of the Commission's order and be
allocated among customer classes such that the relationship between the
specific customer class rates of return to the overall target rate of return
will have the same relationship as the last approved allocation of revenues
used to design base rates. Commencing in 2011, the Commission, after notice and
opportunity for hearing, shall conduct biennial reviews
of the rates, terms and conditions for the provision of generation,
distribution and transmission services by each investor-owned incumbent
electric utility, subject to the following provisions:
1. Rates, terms and conditions for each service shall be
reviewed separately on an unbundled basis, and such reviews shall be conducted
in a single, combined proceeding. The first such
review shall utilize Pursuant to
subdivision A of §56-585.1:1, the
Commission shall conduct a review for a Phase I Utility in 2020, utilizing the
two successive 12-month test periods ending December 31, 2010 2019.
However, the Commission may, in its discretion,
elect to stagger its biennial reviews of utilities by utilizing the two
successive 12-month test periods ending December 31, 2010, for a Phase I
Utility, and utilizing the two successive 12-month test periods ending December
31, 2011, Thereafter, reviews for a Phase II
I Utility,
will be on a triennial basis with subsequent proceedings utilizing
the two three successive
12-month test periods ending December 31 immediately preceding the year in
which such review proceeding is conducted.
Pursuant to Subdivision A of §56-585.1:1, the Commission shall conduct a
review for a Phase II Utility in 2021, utilizing the three successive 12-month
test periods beginning January 1, 2018, and ending December 31, 2020, with
subsequent reviews on a triennial basis utilizing the three successive 12-month
test periods ending December 31 immediately preceding the year in which such
review proceeding is conducted. All such reviews occurring after December 31,
2017, shall be referred to as triennial reviews. For purposes of
this section, a Phase I Utility is an investor-owned incumbent electric utility
that was, as of July 1, 1999, not bound by a rate case settlement adopted by
the Commission that extended in its application beyond January 1, 2002, and a
Phase II Utility is an investor-owned incumbent electric utility that was bound
by such a settlement.
2. Subject to the provisions of subdivision 6, the
fair rates rate of
return on common equity applicable separately to the generation and
distribution services of such utility, and for the two such services combined, and
for any rate adjustment clauses approved under subdivision 5 or 6, shall
be determined by the Commission during each such biennial triennial
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 triennial
review, nor shall the Commission set such return more than 300
basis points higher than such average.
b. In selecting such majority of peer group investor-owned
electric utilities, the Commission shall first remove from such group the two
utilities within such group that have the lowest reported returns of the group,
as well as the two utilities within such group that have the highest reported
returns of the group, and the Commission shall then select a majority of the
utilities remaining in such peer group. In its final order regarding such biennial
triennial review, the Commission shall
identify the utilities in such peer group it selected for the calculation of
such limitation. For purposes of this subdivision, 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 triennial
review, and (iv) it is not an affiliate of the utility subject to
such biennial triennial review.
c. The Commission may, consistent with its precedent for incumbent electric utilities prior to the enactment of Chapters 888 and 933 of the Acts of Assembly of 2007, increase or decrease the utility's combined rate of return based on the Commission's consideration of the utility's performance.
d. In any Current Proceeding, the Commission shall determine whether the Current Return has increased, on a percentage basis, above the Initial Return by more than the increase, expressed as a percentage, in the United States Average Consumer Price Index for all items, all urban consumers (CPI-U), as published by the Bureau of Labor Statistics of the United States Department of Labor, since the date on which the Commission determined the Initial Return. If so, the Commission may conduct an additional analysis of whether it is in the public interest to utilize such Current Return for the Current Proceeding then pending. A finding of whether the Current Return justifies such additional analysis shall be made without regard to any enhanced rate of return on common equity awarded pursuant to the provisions of subdivision 6. Such additional analysis shall include, but not be limited to, a consideration of overall economic conditions, the level of interest rates and cost of capital with respect to business and industry, in general, as well as electric utilities, the current level of inflation and the utility's cost of goods and services, the effect on the utility's ability to provide adequate service and to attract capital if less than the Current Return were utilized for the Current Proceeding then pending, and such other factors as the Commission may deem relevant. If, as a result of such analysis, the Commission finds that use of the Current Return for the Current Proceeding then pending would not be in the public interest, then the lower limit imposed by subdivision 2 a on the return to be determined by the Commission for such utility shall be calculated, for that Current Proceeding only, by increasing the Initial Return by a percentage at least equal to the increase, expressed as a percentage, in the United States Average Consumer Price Index for all items, all urban consumers (CPI-U), as published by the Bureau of Labor Statistics of the United States Department of Labor, since the date on which the Commission determined the Initial Return. For purposes of this subdivision:
"Current Proceeding" means any proceeding conducted under any provisions of this subsection that require or authorize the Commission to determine a fair combined rate of return on common equity for a utility and that will be concluded after the date on which the Commission determined the Initial Return for such utility.
"Current Return" means the minimum fair combined rate of return on common equity required for any Current Proceeding by the limitation regarding a utility's peer group specified in subdivision 2 a.
"Initial Return" means the fair combined rate of return on common equity determined for such utility by the Commission on the first occasion after July 1, 2009, under any provision of this subsection pursuant to the provisions of subdivision 2 a.
e. In addition to other considerations, in setting the return on equity within the range allowed by this section, the Commission shall strive to maintain costs of retail electric energy that are cost competitive with costs of retail electric energy provided by the other peer group investor-owned electric utilities.
f. The determination of such returns shall be made by the Commission on a stand-alone basis, and specifically without regard to any return on common equity or other matters determined with regard to facilities described in subdivision 6.
g. If the combined rate of return on common equity earned by the generation and distribution services is no more than 50 basis points above or below the return as so determined or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, such return is no more than 70 basis points above or below the return as so determined, such combined return shall not be considered either excessive or insufficient, respectively. However, for any test period commencing after December 31, 2012, for a Phase II Utility, and after December 31, 2013, for a Phase I Utility, if the utility has, during the test period or periods under review, earned below the return as so determined, whether or not such combined return is within 70 basis points of the return as so determined, the utility may petition the Commission for approval of an increase in rates in accordance with the provisions of subdivision 8 a as if it had earned more than 70 basis points below a fair combined rate of return, and such proceeding shall otherwise be conducted in accordance with the provisions of this section.
h. Any amount of a utility's earnings directed by the
Commission to be credited to customers' bills pursuant to this section shall
not be considered for the purpose of determining the utility's earnings in any
subsequent biennial triennial review.
3. Each such utility shall make a biennial triennial
filing by March 31 of every other third
year, beginning in 2011, with such filings
commencing for a Phase I Utility in 2020, and such filings commencing for a
Phase II Utility in 2021, consisting of the schedules contained in
the Commission's rules governing utility rate increase applications;
however, if the Commission elects to stagger the dates of the biennial reviews
of utilities as provided in subdivision 1, then each Phase I Utility shall
commence biennial filings in 2011 and each Phase II Utility shall commence
biennial filings in 2012..
Such filing shall encompass the two three
successive 12-month test periods ending December 31 immediately
preceding the year in which such proceeding is conducted, except that the
filing for a Phase I Utility in 2020 shall encompass the two successive
12-month test periods ending December 31, 2019, 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 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 triennial
review proceedings. A Phase I Utility
shall delay for one year the filing of its biennial review from March 31, 2013,
to March 31, 2014, and shall not defer on its books for future recovery any
costs incurred during calendar year 2011, other than as provided in subdivision
7 or §56-249.6, and its subsequent biennial filing shall be made by March 31,
2016, and every two years thereafter.
4. The following costs incurred by the utility shall be deemed
reasonable and prudent: (i) costs for transmission services provided to the
utility by the regional transmission entity of which the utility is a member,
as determined under applicable rates, terms and conditions approved by the
Federal Energy Regulatory Commission, and (ii) costs charged to the utility that
are associated with demand response programs approved by the Federal Energy
Regulatory Commission and administered by the regional transmission entity of
which the utility is a member. Upon petition of a utility at any time after the
expiration or termination of capped rates, but not more than once in any
12-month period, the Commission shall approve a rate adjustment clause under
which such costs, including, without limitation, costs for transmission
service, charges for new and existing transmission facilities, administrative
charges, and ancillary service charges designed to recover transmission costs,
shall be recovered on a timely and current basis from customers.
Retail rates to recover these costs shall be designed using the appropriate
billing determinants in the retail rate schedules.
5. A utility may at any time, after the expiration or termination of capped rates, but not more than once in any 12-month period, petition the Commission for approval of one or more rate adjustment clauses for the timely and current recovery from customers of the following costs:
a. Incremental costs described in clause (vi) of subsection B of §56-582 incurred between July 1, 2004, and the expiration or termination of capped rates, if such utility is, as of July 1, 2007, deferring such costs consistent with an order of the Commission entered under clause (vi) of subsection B of §56-582. The Commission shall approve such a petition allowing the recovery of such costs that comply with the requirements of clause (vi) of subsection B of §56-582;
b. Projected and actual costs 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 2. The Commission shall only approve such a petition if it finds that the program is in the public interest. As part of such cost recovery, the Commission, if requested by the utility, shall allow for the recovery of revenue reductions related to energy efficiency programs. The Commission shall only allow such recovery to the extent that the Commission determines such revenue has not been recovered through margins from incremental off-system sales as defined in §56-249.6 that are directly attributable to energy efficiency programs.
None of the costs of new energy efficiency programs of an electric utility, including recovery of revenue reductions, shall be assigned to any customer that has a verifiable history of having used more than 10 megawatts of demand from a single meter of delivery. Nor shall any of the costs of new energy efficiency programs of an electric utility, including recovery of revenue reductions, be incurred by any large general service customer as defined herein that has notified the utility of non-participation in such energy efficiency program or programs. A large general service customer is a customer that has a verifiable history of having used more than 500 kilowatts of demand from a single meter of delivery. Non-participation in energy efficiency programs shall be allowed by the Commission if the large general service customer has, at the customer's own expense, implemented energy efficiency programs that have produced or will produce measured and verified results consistent with industry standards and other regulatory criteria stated in this section. The Commission shall, no later than November 15, 2009, promulgate rules and regulations to accommodate the process under which such large general service customers shall file notice for such an exemption and (i) establish the administrative procedures by which eligible customers will notify the utility and (ii) define the standard criteria that must be satisfied by an applicant in order to notify the utility. In promulgating such rules and regulations, the Commission may also specify the timing as to when a utility shall accept and act on such notice, taking into consideration the utility's integrated resource planning process as well as its administration of energy efficiency programs that are approved for cost recovery by the Commission. The notice of non-participation by a large general service customer, to be given by March 1 of a given year, shall be for the duration of the service life of the customer's energy efficiency program. The Commission on its own motion may initiate steps necessary to verify such non-participants' achievement of energy efficiency if the Commission has a body of evidence that the non-participant has knowingly misrepresented its energy efficiency achievement. A utility shall not charge such large general service customer, as defined by the Commission, for the costs of installing energy efficiency equipment beyond what is required to provide electric service and meter such service on the customer's premises if the customer provides, at the customer's expense, equivalent energy efficiency equipment. In all relevant proceedings pursuant to this section, the Commission shall take into consideration the goals of economic development, energy efficiency and environmental protection in the Commonwealth;
d. Projected and actual costs of participation in a renewable energy portfolio standard program pursuant to §56-585.2 that are not recoverable under subdivision 6. The Commission shall approve such a petition allowing the recovery of such costs as are provided for in a program approved pursuant to §56-585.2;
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; and
f. Projected and actual costs, not currently in rates, for the utility to design, implement, and operate programs approved by the Commission that accelerate the vegetation management of distribution rights-of-way. No costs shall be allocated to or recovered from customers that are served within the large general service rate classes for a Phase II Utility or that are served at subtransmission or transmission voltage, or take delivery at a substation served from subtransmission or transmission voltage, for a Phase I Utility.
The Commission shall have the authority to determine the duration or amortization period for any adjustment clause approved under this subdivision.
6. To ensure the generation and delivery of a reliable and
adequate supply of electricity, to meet the utility's projected native load
obligations and to promote economic development, a utility may at any time,
after the expiration or termination of capped rates, petition the Commission
for approval of a rate adjustment clause for recovery on a timely and current
basis from customers of the costs of (i) a coal-fueled generation facility that
utilizes Virginia coal and is located in the coalfield region of the
Commonwealth as described in §15.2-6002, regardless of whether such facility
is located within or without the utility's service territory, (ii) one or more
other generation facilities, (iii) one or more major unit modifications of
generation facilities, including the costs of any system or equipment upgrade,
system or equipment replacement, or other cost reasonably appropriate to extend
the combined operating license for or the operating life of one or more
generation facilities utilizing nuclear power, (iv) one or more new underground
facilities to replace one or more existing overhead distribution facilities of
69 kilovolts or less located within the Commonwealth, or (v)
one or more pumped hydroelectricity generation and storage facilities that utilize
on-site or off-site renewable energy resources as all or a portion of their
power source and such facilities and associated resources are located in the
coalfield region of the Commonwealth as described in §15.2-6002, regardless of
whether such facility is located within or without the utility's service
territory, or (vi) one or more electric distribution grid
transformation projects; however, subject to the provisions of the
following sentence, the utility shall not file a petition under clause (iv)
more often than annually and, in such petition, shall not seek any annual
incremental increase in the level of investments associated with such a
petition that exceeds five percent of such utility's distribution rate base, as
such rate base was determined for the most recently ended 12-month test period
in the utility's latest biennial triennial review
proceeding conducted pursuant to subdivision 3 and concluded by final order of
the Commission prior to the date of filing of such petition under clause (iv).
In all proceedings regarding petitions filed under clause (iv)
or (vi), the level of investments approved for recovery in such
proceedings shall be in addition to, and not in lieu of, levels of investments
previously approved for recovery in prior proceedings under clause (iv).
or (vi), as applicable. Such a petition concerning facilities
described in clause (ii) that utilize nuclear power, facilities described in
clause (ii) that are coal-fueled and will be built by a Phase I Utility, or
facilities described in clause (i) may also be filed before the expiration or
termination of capped rates. A utility that constructs or makes modifications
to any such facility, or purchases any facility consisting of at least one
megawatt of generating capacity using energy derived from sunlight and located
in the Commonwealth and that utilizes goods or services sourced, in whole or in
part, from one or more Virginia businesses, shall have the right to recover the
costs of the facility, as accrued against income, through its rates, including
projected construction work in progress, and any associated allowance for funds
used during construction, planning, development and construction or acquisition
costs, life-cycle costs, costs related to assessing the feasibility of
potential sites for new underground facilities, and costs of infrastructure
associated therewith, plus, as an incentive to undertake such projects, an
enhanced rate of return on common equity calculated as specified below;
however, in determining the amounts recoverable under a rate adjustment clause
for new underground facilities, the Commission shall not consider, or increase
or reduce such amounts recoverable because of (a) the operation and maintenance
costs attributable to either the overhead distribution facilities being
replaced or the new underground facilities or (b) any other costs attributable
to the overhead distribution facilities being replaced. Notwithstanding the
preceding sentence, the costs described in clauses (a) and (b) thereof shall
remain eligible for recovery from customers through the utility's base rates
for distribution service. A utility filing a petition for approval to construct
or purchase a facility consisting of at least one megawatt of generating
capacity using energy derived from sunlight and located in the Commonwealth and
that utilizes goods or services sourced, in whole or in part, from one or more
Virginia businesses may propose a rate adjustment clause based on a market
index in lieu of a cost of service model for such facility. A utility seeking
approval to construct or purchase a generating facility described in clause (i)
or (ii) shall demonstrate that it has considered and weighed alternative
options, including third-party market alternatives, in its selection process.
The costs of the facility, other than return on projected construction work in
progress and allowance for funds used during construction, shall not be
recovered prior to the date a facility constructed by the utility and described
in clause (i), (ii), or (iii) or (v)
begins commercial operation, the date the utility becomes the owner of a
purchased generation facility consisting of at least one megawatt of generating
capacity using energy derived from sunlight and located in the Commonwealth and
that utilizes goods or services sourced, in whole or in part, from one or more
Virginia businesses, or the date new underground facilities are classified by
the utility as plant in service. Such enhanced rate of return on common equity
shall be applied to allowance for funds used during construction and to
construction work in progress during the construction phase of the facility and
shall thereafter be applied to the entire facility during the first portion of
the service life of the facility. The first portion of the service life shall
be as specified in the table below; however, the Commission shall determine the
duration of the first portion of the service life of any facility, within the
range specified in the table below, which determination shall be consistent
with the public interest and shall reflect the Commission's determinations
regarding how critical the facility may be in meeting the energy needs of the
citizens of the Commonwealth and the risks involved in the development of the
facility. After the first portion of the service life of the facility is
concluded, the utility's general rate of return shall be applied to such facility
for the remainder of its service life. As used herein, the service life of the
facility shall be deemed to begin on the date a facility constructed by the
utility and described in clause (i), (ii), or (iii)
or (v) begins commercial operation, the date the utility becomes
the owner of a purchased generation facility consisting of at least one
megawatt of generating capacity using energy derived from sunlight and located
in the Commonwealth and that utilizes goods or services sourced, in whole or in
part, from one or more Virginia businesses, or the date new underground
facilities or new electric distribution grid transformation
projects are classified by the utility as plant in service, and
such service life shall be deemed equal in years to the life of that facility
as used to calculate the utility's depreciation expense. Such enhanced rate of
return on common equity shall be calculated by adding the basis points
specified in the table below to the utility's general rate of return, and such
enhanced rate of return shall apply only to the facility that is the subject of
such rate adjustment clause. Allowance for funds used during construction shall
be calculated for any such facility utilizing the utility's actual capital
structure and overall cost of capital, including an enhanced rate of return on
common equity as determined pursuant to this subdivision, until such
construction work in progress is included in rates. The construction of any
facility described in clause (i) or (v) is in the public interest, and in
determining whether to approve such facility, the Commission shall liberally
construe the provisions of this title. The construction or purchase by a
utility of one or more generation facilities with at least one megawatt of
generating capacity, and with an aggregate rated capacity that does not exceed 500
4,000 megawatts, including rooftop
solar installations with a capacity of not less than 50 kilowatts, and with an
aggregate capacity of 50 megawatts, that use energy derived from
sunlight and are located in the Commonwealth, regardless of whether any of such
facilities are located within or without the utility's service territory, is in
the public interest, and in determining whether to approve such facility, the
Commission shall liberally construe the provisions of this title. A utility may
enter into short-term or long-term power purchase contracts for the power
derived from sunlight generated by such generation facility prior to purchasing
the generation facility. The replacement of any subset of a utility's existing
overhead distribution tap lines that have, in the aggregate, an average of nine
or more total unplanned outage events-per-mile over a preceding 10-year period
with new underground facilities in order to improve electric service
reliability is in the public interest. In determining whether to approve
petitions for rate adjustment clauses for such new underground facilities that
meet this criteria, and in determining the level of costs to be recovered
thereunder, the Commission shall liberally construe the provisions of this
title. There shall be a rebuttable presumption that the The
conversion of any such facilities will
on or after September 1, 2016, is deemed to provide
local and system-wide benefits, that such new
underground facilities are and to be
cost beneficial, and that the costs associated with such
new underground facilities are deemed to be reasonably
and prudently incurred and shall be approved for recovery by the
Commission pursuant to this subdivision provided that the total costs
associated with the replacement of any subset of existing overhead distribution
tap lines proposed by the utility with
new underground facilities, exclusive of financing
costs, shall not exceed an average cost per customer of $20,000, with such
customers including those served directly by or downline of the tap lines
proposed for conversion and, further, such total costs
shall not exceed an average cost per mile of tap lines converted, exclusive of
financing costs, of $750,000. A utility may, without regard for whether it has
petitioned for any rate adjustment clause pursuant to clause (vi), petition the
Commission, not more than once annually, for approval of a plan for electric
distribution grid transformation projects. In ruling upon such a petition, the
Commission shall consider whether the utility's plan for such projects, and the
projected costs associated therewith, are reasonable and prudent. Such
petition shall be considered on a stand-alone basis without regard to the other
costs, revenues, investments or earnings of the utility, without regard to
whether the costs associated with such projects will be recovered through a
rate adjustment clause under this subdivision or through the utility's rates
for generation and distribution services, and without regard to whether such
costs will be the subject of a customer credit offset, as applicable, pursuant
to subdivision 8 d. The Commission's final order regarding any such petition
for approval of an electric distribution grid transformation plan shall be
entered by the Commission not more than six months after the date of filing
such petition. The Commission shall likewise enter its final order with
respect to any petition by a utility for a certificate to construct and operate
a generating facility or facilities utilizing energy derived from sunlight,
pursuant to §56-580.D of this chapter, within six months after the date of
filing such petition. The basis points to be added to the
utility's general rate of return to calculate the enhanced rate of return on
common equity, and the first portion of that facility's service life to which
such enhanced rate of return shall be applied, shall vary by type of facility,
as specified in the following table:
|
Type of Generation Facility |
Basis Points |
First Portion of Service Life |
|
Nuclear-powered |
200 |
Between 12 and 25 years |
|
Carbon capture compatible, clean-coal powered |
200 |
Between 10 and 20 years |
|
Renewable powered, other than landfill gas powered |
200 |
Between 5 and 15 years |
|
Coalbed methane gas powered |
150 |
Between 5 and 15 years |
|
Landfill gas powered |
200 |
Between 5 and 15 years |
|
Conventional coal or combined-cycle combustion turbine |
100 |
Between 10 and 20 years |
For generating facilities other than those utilizing nuclear power constructed pursuant to clause (ii) or those utilizing energy derived from offshore wind, as of July 1, 2013, only those facilities as to which a rate adjustment clause under this subdivision has been previously approved by the Commission, or as to which a petition for approval of such rate adjustment clause was filed with the Commission, on or before January 1, 2013, shall be entitled to the enhanced rate of return on common equity as specified in the above table during the construction phase of the facility and the approved first portion of its service life.
For generating facilities within the Commonwealth utilizing
nuclear power or those utilizing energy derived from offshore wind projects
located in waters off the Commonwealth's Atlantic shoreline, such facilities
shall continue to be eligible for an enhanced rate of return on common equity
during the construction phase of the facility and the approved first portion of
its service life of between 12 and 25 years in the case of a facility utilizing
nuclear power and for a service life of between 5 and 15 years in the case of a
facility utilizing energy derived from offshore wind, provided, however, that,
as of July 1, 2013, the enhanced return for such facilities constructed
pursuant to clause (ii) shall be 100 basis points, which shall be added to the
utility's general rate of return as determined under subdivision 2. Thirty
percent of all costs of such a facility utilizing nuclear power that the
utility incurred between July 1, 2007, and December 31, 2013, and all of such
costs incurred after December 31, 2013, may be deferred by the utility and
recovered through a rate adjustment clause under this subdivision at such time
as the Commission provides in an order approving such a rate adjustment clause.
The remaining 70 percent of all costs of such a facility that the utility
incurred between July 1, 2007, and December 31, 2013, shall not be deferred for
recovery through a rate adjustment clause under this subdivision; however, such
remaining 70 percent of all costs shall be recovered ratably through existing
base rates as determined by the Commission in the test periods under review in
the utility's next biennial review filed after July 1,
2014. Thirty percent of all costs of such a facility utilizing energy derived
from offshore wind that the utility incurred between July 1, 2007, and December
31, 2013, and all of such costs incurred after December 31, 2013, may be
deferred by the utility and recovered through a rate adjustment clause under
this subdivision at such time as the Commission provides in an order approving
such a rate adjustment clause. The remaining 70 percent of all costs of such a
facility that the utility incurred between July 1, 2007, and December 31, 2013,
shall not be deferred for recovery through a rate adjustment clause under this
subdivision; however, such remaining 70 percent of all costs shall be recovered
ratably through existing base rates as determined by the Commission in the test
periods under review in the utility's next biennial review
filed after July 1, 2014.
In connection with planning to meet forecasted demand for electric generation supply and assure the adequate and sufficient reliability of service, consistent with §56-598, planning and development activities for a new nuclear generation facility or facilities are in the public interest.
In connection with planning to meet forecasted demand for
electric generation supply and assure the adequate and sufficient reliability
of service, consistent with §56-598, planning and development activities for a
new utility-owned and utility-operated generating facility or facilities
utilizing energy derived from sunlight with an aggregate
capacity of 500 megawatts, or from offshore wind, are in the
public interest.
Construction, purchasing, or leasing activities for a new utility-owned and utility-operated generating facility or facilities utilizing energy derived from sunlight with an aggregate capacity of 4,000 megawatts, including rooftop solar installations with a capacity of not less than 50 kilowatts, and with an aggregate capacity of 50 megawatts, or from onshore wind, or from offshore wind with an aggregate capacity of not more than 16 megawatts, are in the public interest. To the extent a utility elects to recover the costs of any such new generation facility or facilities through its rates for generation and distribution services and does not petition and receive approval from the Commission for recovery of such costs through a rate adjustment clause described in clause (ii), the Commission shall provide for a customer credit reinvestment offset, as applicable, pursuant to subdivision 8 d.
Electric distribution grid transformation projects are in the public interest. To the extent a utility elects to recover the costs of such electric distribution grid transformation projects through its rates for generation and distribution services, and does not petition and receive approval from the Commission for recovery of such costs through a rate adjustment clause described in clause (vi), the Commission shall provide for a customer credit reinvestment offset, as applicable, pursuant to subdivision 8 d.
Neither generation facilities described in clause (ii) that utilize simple-cycle combustion turbines nor new underground facilities shall receive an enhanced rate of return on common equity as described herein, but instead shall receive the utility's general rate of return during the construction phase of the facility and, thereafter, for the entire service life of the facility. No rate adjustment clause for new underground facilities shall allocate costs to, or provide for the recovery of costs from, customers that are served within the large power service rate class for a Phase I Utility and the large general service rate classes for a Phase II Utility. New underground facilities are hereby declared to be ordinary extensions or improvements in the usual course of business under the provisions of §56-265.2.
As used in this subdivision, a generation facility is (1) "coalbed methane gas powered" if the facility is fired at least 50 percent by coalbed methane gas, as such term is defined in §45.1-361.1, produced from wells located in the Commonwealth, and (2) "landfill gas powered" if the facility is fired by methane or other combustible gas produced by the anaerobic digestion or decomposition of biodegradable materials in a solid waste management facility licensed by the Waste Management Board. A landfill gas powered facility includes, in addition to the generation facility itself, the equipment used in collecting, drying, treating, and compressing the landfill gas and in transmitting the landfill gas from the solid waste management facility where it is collected to the generation facility where it is combusted.
For purposes of this subdivision, "general rate of
return" means the fair combined rate of return on common equity as it is
determined by the Commission from time to time for
such utility pursuant to subdivision 2. In any proceeding
under this subdivision conducted prior to the conclusion of the first biennial
review for such utility, the Commission shall determine a general rate of
return for such utility in the same manner as it would in a biennial review
proceeding.
Notwithstanding any other provision of this subdivision, if
the Commission finds during the biennial triennial
review conducted for a Phase II Utility in 2018 2021
that such utility has not filed applications for all necessary
federal and state regulatory approvals to construct one or more nuclear-powered
or coal-fueled generation facilities that would add a total capacity of at
least 1500 megawatts to the amount of the utility's generating resources as
such resources existed on July 1, 2007, or that, if all such approvals have
been received, that the utility has not made reasonable and good faith efforts
to construct one or more such facilities that will provide such additional
total capacity within a reasonable time after obtaining such approvals, then
the Commission, if it finds it in the public interest, may reduce on a
prospective basis any enhanced rate of return on common equity previously
applied to any such facility to no less than the general rate of return for
such utility and may apply no less than the utility's general rate of return to
any such facility for which the utility seeks approval in the future under this
subdivision.
Notwithstanding any other provision of this subdivision, if a Phase II utility obtains approval from the Commission of a rate adjustment clause pursuant to subdivision A 6 associated with a test or demonstration project involving a generation facility utilizing energy from offshore wind, and such utility has not, as of July 1, 2023, commenced construction of a full-scale offshore wind generation facility, then the Commission, if it finds it in the public interest, may direct that the costs associated with any such rate adjustment clause involving said test or demonstration project shall thereafter no longer be recovered through a rate adjustment clause pursuant to subdivision 6, and shall instead be recovered through the utility's rates for generation and distribution services, with no change in such rates for generation and distribution services as a result of the combination of such costs with the other costs, revenues and investments included in the utility's rates for generation and distribution services. Any such costs shall remain combined with the utility's other costs, revenues and investments included in its rates for generation and distribution services until such costs are fully recovered.
7. Any petition filed pursuant to subdivision 4, 5, or 6 shall
be considered by the Commission on a stand-alone basis without regard to the
other costs, revenues, investments, or earnings of the utility. Any costs
incurred by a utility prior to the filing of such petition, or during the
consideration thereof by the Commission, that are proposed for recovery in such
petition and that are related to subdivision 5 a, or that are related to
facilities and projects described in clause (i) of subdivision 6, or that are
related to new underground facilities described in clause (iv) of subdivision
6, shall be deferred on the books and records of the utility until the
Commission's final order in the matter, or until the implementation of any
applicable approved rate adjustment clauses, whichever is later. Except as
otherwise provided in subdivision 6, any costs prudently incurred on or after
July 1, 2007, by a utility prior to the filing of such petition, or during the
consideration thereof by the Commission, that are proposed for recovery in such
petition and that are related to facilities and projects described in clause
(ii) or clause (iii) of subdivision 6 that utilize nuclear power, or
coal-fueled facilities and projects described in clause (ii) of subdivision 6
if such coal-fueled facilities will be built by a Phase I Utility, shall be deferred
on the books and records of the utility until the Commission's final order in
the matter, or until the implementation of any applicable approved rate
adjustment clauses, whichever is later. Any costs prudently incurred after the
expiration or termination of capped rates related to other matters described in
subdivision 4, 5, or 6 shall be deferred beginning only upon the expiration or
termination of capped rates, provided, however, that no provision of this act
shall affect the rights of any parties with respect to the rulings of the
Federal Energy Regulatory Commission in PJM Interconnection LLC and Virginia
Electric and Power Company, 109 F.E.R.C. P 61,012 (2004). A utility shall
establish a regulatory asset for regulatory accounting and ratemaking purposes
under which it shall defer its operation and maintenance costs incurred in
connection with (i) the refueling of any nuclear-powered generating plant and
(ii) other work at such plant normally performed during a refueling outage. The
utility shall amortize such deferred costs over the refueling cycle, but in no
case more than 18 months, beginning with the month in which such plant resumes
operation after such refueling. The refueling cycle shall be the applicable
period of time between planned refueling outages for such plant. As of January
1, 2014, such amortized costs are a component of base rates, recoverable in
base rates only ratably over the refueling cycle rather than when such outages
occur, and are the only nuclear refueling costs recoverable in base rates. This
provision shall apply to any nuclear-powered generating plant refueling outage
commencing after December 31, 2013, and the Commission shall treat the deferred
and amortized costs of such regulatory asset as part of the utility's costs for
the purpose of proceedings conducted (a) with respect to biennial triennial
filings under subdivision 3 made on and after July 1, 2014, and
(b) pursuant to §56-245 or the Commission's rules governing utility rate
increase applications as provided in subsection B. This provision shall not be
deemed to change or reset base rates.
The Commission's final order regarding any petition filed pursuant to subdivision 4, 5, or 6 shall be entered not more than three months, eight months, and nine months, respectively, after the date of filing of such petition. If such petition is approved, the order shall direct that the applicable rate adjustment clause be applied to customers' bills not more than 60 days after the date of the order, or upon the expiration or termination of capped rates, whichever is later.
8. In any biennial triennial review
proceeding, the following utility generation and distribution costs not
proposed for recovery under any other subdivision of this subsection, as
recorded per books by the utility for financial reporting purposes and accrued
against income, shall be attributed to the test periods under review
and deemed fully recovered in the period recorded: costs
associated with asset impairments related to early retirement determinations
made by the utility prior to December 31, 2012, for
utility generation plant facilities fueled
by coal, natural gas or oil or for automated meter reading electric
distribution service meters; costs associated with projects necessary to comply
with state or federal environmental laws, regulations or judicial or
administrative orders relating to coal combustion by-product management which
the utility does not petition to recover through a rate adjustment clause
pursuant to subdivision 5 e; costs associated with severe weather
events; and costs associated with natural disasters. Such costs shall be deemed
to have been recovered from customers through rates for generation and
distribution services in effect during the test periods under review unless
such costs, individually or in the aggregate, together with the utility's other
costs, revenues, and investments to be recovered through rates for generation
and distribution services, result in the utility's earned return on its
generation and distribution services for the combined test periods under review
to fall more than 50 basis points below the fair combined rate of return
authorized under subdivision 2 for such periods or, for any test period
commencing after December 31, 2012, for a Phase II Utility and after December
31, 2013, for a Phase I Utility, to fall more than 70 basis points below the
fair combined rate of return authorized under subdivision 2 for such periods.
In such cases, the Commission shall, in such biennial triennial
review proceeding, authorize deferred recovery of such costs and
allow the utility to amortize and recover such deferred costs over future
periods as determined by the Commission. The aggregate amount of such deferred
costs shall not exceed an amount that would, together with the utility's other
costs, revenues, and investments to be recovered through rates for generation
and distribution services, cause the utility's earned return on its generation
and distribution services to exceed the fair rate of return authorized under
subdivision 2, less 50 basis points, for the combined test periods under review
or, for any test period commencing after December 31, 2012, for a Phase II
Utility and after December 31, 2013, for a Phase I Utility, to exceed the fair
rate of return authorized under subdivision 2 less 70 basis points. Nothing in
this section shall limit the Commission's authority, pursuant to the provisions
of Chapter 10 (§56-232 et seq.), including specifically §56-235.2, following
the review of combined test period earnings of the utility in a biennial
triennial review, for normalization of
nonrecurring test period costs and annualized adjustments for future costs, in
determining any appropriate increase or decrease in the utility's rates for
generation and distribution services pursuant to subdivision 8 a or 8 c.
If the Commission determines as a result of such biennial
triennial review that:
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 its generation and distribution services or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, more than 70 basis points below a fair combined rate of return on its generation and distribution services, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, the Commission shall order increases to the utility's rates necessary to provide the opportunity to fully recover the costs of providing the utility's services and to earn not less than such fair combined rate of return, using the most recently ended 12-month test period as the basis for determining the amount of the rate increase necessary. However, the Commission may not order such rate increase unless it finds that the resulting rates are necessary to provide the utility with the opportunity to fully recover its costs of providing its services and to earn not less than a fair combined rate of return on both its generation and distribution services, as determined in subdivision 2, without regard to any return on common equity or other matters determined with respect to facilities described in subdivision 6, using the most recently ended 12-month test period as the basis for determining the permissibility of any rate increase under the standards of this sentence, and the amount thereof;
b. The utility has, during the test period or test periods
under review, considered as a whole, earned more than 50 basis points above a
fair combined rate of return on its generation and distribution services or,
for any test period commencing after December 31, 2012, for a Phase II Utility
and after December 31, 2013, for a Phase I Utility, more than 70 basis points
above a fair combined rate of return on its generation and distribution
services, as determined in subdivision 2, without regard to any return on
common equity or other matters determined with respect to facilities described
in subdivision 6, the Commission shall, subject to the provisions of subdivision
subdivisions 8 d and 9, direct that 60
percent of the amount of such earnings that were more than 50 basis points, or,
for any test period commencing after December 31, 2012, for a Phase II Utility
and after December 31, 2013, for a Phase I Utility, that 70 percent of the
amount of such earnings that were more than 70 basis points, above such fair
combined rate of return for the test period or periods under review, considered
as a whole, shall be credited to customers' bills. Any such credits shall be
amortized over a period of six to 12 months, as determined at the discretion of
the Commission, following the effective date of the Commission's order, and
shall be allocated among customer classes such that the relationship between
the specific customer class rates of return to the overall target rate of
return will have the same relationship as the last approved allocation of
revenues used to design base rates; or
c. Such biennial triennial review
is the second consecutive biennial triennial review
occurring after December 31, 2017, 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 its generation and distribution services or, for any test
period commencing after December 31, 2012, for a Phase II Utility and after
December 31, 2013, for a Phase I Utility, more than 70 basis points above a
fair combined rate of return on its generation and distribution services, as
determined in subdivision 2, without regard to any return on common equity or
other matter determined with respect to facilities described in subdivision 6, and the combined aggregate level of capital investment
made by the utility during the test periods under review in the two consecutive
triennial review proceedings in new utility-owned generation facilities
utilizing energy derived from sunlight, or from onshore or offshore wind, and
in electric distribution grid transformation projects which the Commission has
not approved for recovery through a rate adjustment clause pursuant to
subdivision 6, does not equal or exceed 70 percent of the earnings above the
utility's fair combined rate of return on its generation and distribution
services for the combined test periods under review in the two consecutive
triennial review proceedings, the
Commission shall, subject to the provisions of subdivision 9 and in addition to
the actions authorized in subdivision b, also order reductions to the utility's
rates it finds appropriate. However, the Commission may not order such rate
reduction unless it finds that the resulting rates will provide the utility
with the opportunity to fully recover its costs of providing its services and
to earn not less than a fair combined rate of return on its generation and distribution
services, as determined in subdivision 2, without regard to any return on
common equity or other matters determined with respect to facilities described
in subdivision 6, using the most recently ended 12-month test period as the
basis for determining the permissibility of any rate reduction under the
standards of this sentence, and the amount thereof; or
d. In any triennial review proceeding conducted after December 31, 2017, the Commission shall determine, prior to directing that 70 percent of earnings above the utility's fair combined rate of return on its generation and distribution services for the test period or periods under review be credited to customer bills pursuant to subdivision 8 b, the aggregate level of capital investment made by the utility during the test period or periods under review in both (i) new utility-owned generation facilities utilizing energy derived from sunlight, or from onshore or offshore wind, and (ii) electric distribution grid transformation projects which the Commission has not approved for recovery through a rate adjustment clause pursuant to subdivision 6, as determined by the utility's plant balances related to such investments as recorded per books by the utility for financial reporting purposes as of the end of the most recent test period under review. Any such combined capital investment amounts shall offset any customer bill credit amounts, on a dollar for dollar basis, up to the aggregate level of invested or committed capital under clauses (i) and (ii). The aggregate level of invested or committed capital under clauses (i) and (ii) is referred to in this subdivision as the customer credit reinvestment offset. If 70 percent of the amount of earnings above the utility's fair combined rate of return on its generation and distribution services, as determined in subdivision 2, exceeds the aggregate level of invested capital in new utility-owned generation facilities utilizing energy derived from sunlight, or from onshore or offshore wind, and electric distribution grid transformation projects, as provided in clauses (i) and (ii), during the test period or periods under review, then the amount of such excess shall be credited to customer bills as provided in subdivision 8 b in connection with the subsequent triennial review proceeding, unless the aggregate level of capital investment in new utility-owned generation facilities utilizing energy derived from sunlight, or from onshore or offshore wind, and electric distribution grid transformation projects, as provided in clauses (i) and (ii), over the test periods under review in the subsequent triennial review proceeding which the Commission has not approved for recovery through a rate adjustment clause pursuant to subdivision 6, exceeds both this excess amount and 70 percent of any earnings above the utility's fair combined rate of return for the test period or periods under review in the subsequent triennial review proceeding. Any costs associated with new utility-owned generation facilities utilizing energy derived from sunlight, or from onshore or offshore wind, or electric distribution grid transformation projects, that are the subject of any customer credit reinvestment offset pursuant to this subdivision shall thereafter be recovered through the utility's rates for generation and distribution services over the service life of such facilities, shall be included in the utility's costs, revenues and investments in future triennial review proceedings conducted pursuant to subdivision 2 until such costs are fully recovered, with no rate base or other cost of service adjustment associated with the customer credit reinvestment offset pursuant to this subdivision, and shall not be the subject of a rate adjustment clause petition pursuant to subdivision 6. Only such costs of new utility-owned generation facilities utilizing energy derived from sunlight, or from onshore or offshore wind, or electric distribution grid transformation projects which have not included in any customer credit reinvestment offset pursuant to this subdivision, and not otherwise recovered through the utility's rates for generation and distribution services, may be the subject of a rate adjustment clause petition by the utility pursuant to subdivision 6.
The Commission's final order regarding such biennial
triennial review shall be entered not
more than eight months after the date of filing, and any revisions in rates or
credits so ordered shall take effect not more than 60 days after the date of
the order. The fair combined rate of return on common equity determined
pursuant to subdivision 2 in such biennial triennial
review shall apply, for purposes of reviewing the utility's
earnings on its rates for generation and distribution services, to the entire two
three successive 12-month test periods
ending December 31 immediately preceding the year of the utility's subsequent biennial
triennial review filing under
subdivision 3 and shall apply to applicable rate adjustment
clauses under subdivisions 5 and 6 prospectively from the date the Commission's
final order in the triennial review proceeding, utilizing rate adjustment
clause true-up protocols as the commission in its discretion may determine.
9. If, as a result of a biennial triennial
review required under this subsection and conducted with respect
to any test period or periods under review ending later than December 31, 2010
(or, if the Commission has elected to stagger its biennial reviews of utilities
as provided in subdivision 1, under review ending later than December 31, 2010,
for a Phase I Utility, or December 31, 2011, for a Phase II Utility), the
Commission finds, with respect to such test period or periods considered as a
whole, that (i) any utility has, during the test period or periods under
review, considered as a whole, earned more than 50 basis points above a fair
combined rate of return on its generation and distribution services or, for any
test period commencing after December 31, 2012, for a Phase II Utility and
after December 31, 2013, for a Phase I Utility, more than 70 basis points above
a fair combined rate of return on its generation and distribution services, as
determined in subdivision 2, without regard to any return on common equity or
other matters determined with respect to facilities described in subdivision 6,
and (ii) the total aggregate regulated rates of such utility at the end of the
most recently-ended 12-month test period exceeded the annual increases in the
United States Average Consumer Price Index for all items, all urban consumers
(CPI-U), as published by the Bureau of Labor Statistics of the United States
Department of Labor, compounded annually, when compared to the total aggregate
regulated rates of such utility as determined pursuant to the 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 subdivisions 8 b and c are more consistent with the public interest, direct
that any or all earnings for such test period or periods under review,
considered as a whole that were more than 50 basis points, or, for any test
period commencing after December 31, 2012, for a Phase II Utility and after
December 31, 2013, for a Phase I Utility, more than 70 basis points, above such
fair combined rate of return shall be credited to customers' bills, in lieu of
the provisions of subdivisions 8 b and c., provided that no
credits shall be provided pursuant to this subdivision in connection with any
triennial review unless such bill credits would be payable pursuant to the
provisions of subdivision 8 d, and any credits under this subdivision shall be
calculated net of any customer credit reinvestment offset amounts under
subdivision 8 d. Any such credits shall be amortized and allocated
among customer classes in the manner provided by subdivision 8 b. For purposes
of this subdivision:
"Base period" means (i) the test period ending December 31, 2010 (or, if the Commission has elected to stagger its biennial reviews of utilities as provided in subdivision 1, the test period ending December 31, 2010, for a Phase I Utility, or December 31, 2011, for a Phase II Utility), or (ii) the most recent test period with respect to which credits have been applied to customers' bills under the provisions of this subdivision, whichever is later.
"Total aggregate regulated rates" shall include: (i) fuel tariffs approved pursuant to §56-249.6, except for any increases in fuel tariffs deferred by the Commission for recovery in periods after December 31, 2010, pursuant to the provisions of clause (ii) of subsection C of §56-249.6; (ii) rate adjustment clauses implemented pursuant to subdivision 4 or 5; (iii) revisions to the utility's rates pursuant to subdivision 8 a; (iv) revisions to the utility's rates pursuant to the Commission's rules governing utility rate increase applications, as permitted by subsection B, occurring after July 1, 2009; and (v) base rates in effect as of July 1, 2009.
10. 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 subdivisions 8 a and c, and without regard to the cost of capital, capital structure, revenues, expenses or investments of any other entity with which such utility may be affiliated. In particular, and without limitation, the Commission shall determine the federal and state income tax costs for any such utility that is part of a publicly traded, consolidated group as follows: (i) such utility's apportioned state income tax costs shall be calculated according to the applicable statutory rate, as if the utility had not filed a consolidated return with its affiliates, and (ii) such utility's federal income tax costs shall be calculated according to the applicable federal income tax rate and shall exclude any consolidated tax liability or benefit adjustments originating from any taxable income or loss of its affiliates.
B. Nothing in this section shall preclude an investor-owned incumbent electric utility from applying for an increase in rates pursuant to § 56-245 or the Commission's rules governing utility rate increase applications; however, in any such filing, a fair rate of return on common equity shall be determined pursuant to subdivision A 2. Nothing in this section shall preclude such utility's recovery of fuel and purchased power costs as provided in § 56-249.6.
C. Except as otherwise provided in this section, the Commission shall exercise authority over the rates, terms and conditions of investor-owned incumbent electric utilities for the provision of generation, transmission and distribution services to retail customers in the Commonwealth pursuant to the provisions of Chapter 10 (§56-232 et seq.), including specifically §56-235.2.
D. The Except as otherwise
provided in this section, the Commission may determine, during any
proceeding authorized or required by this section, the reasonableness or
prudence of any cost incurred or projected to be incurred, by a utility in
connection with the subject of the proceeding. A determination of the
Commission regarding the reasonableness or prudence of any such cost shall be
consistent with the Commission's authority to determine the reasonableness or
prudence of costs in proceedings pursuant to the provisions of Chapter 10 (§
56-232 et seq.). In determining the reasonableness or prudence of a utility
providing energy and capacity to its customers from renewable energy resources,
the Commission shall consider the extent to which such renewable energy resources,
whether utility-owned or by contract, further the objectives of the
Commonwealth Energy Policy set forth in §§67-101 and 67-102, and shall also
consider whether the costs of such resources is likely to result in
unreasonable increases in rates paid by consumers.
E. The Commission shall promulgate such rules and regulations as may be necessary to implement the provisions of this section.
§56-585.1:1. Transitional Rate Period: review of rates, terms and conditions for utility generation facilities.
Notwithstanding the provisions of §§56-249.6 and
56-585.1:
A. No biennial reviews of the rates, terms, and conditions for
any service of a Phase I Utility, as defined in §56-585.1, shall be conducted
at any time by the State Corporation Commission for the four successive
12-month test periods beginning January 1, 2014, and ending December 31, 2017.
No biennial reviews of the rates, terms, and conditions for any service of a
Phase II Utility, as defined in §56-585.1, shall be conducted at any time by
the State Corporation Commission for the five
three successive 12-month test periods
beginning January 1, 2015, and ending December 31, 20192017.
Such test periods beginning January 1, 2014, and ending December 31, 2017, for
a Phase I Utility, and beginning January 1, 2015, and ending December 31, 20192017,
for a Phase II Utility, are collectively referred to herein as the
"Transitional Rate Period." Review of recovery of fuel and purchase
power costs shall continue during the Transitional Rate Period in accordance
with §56-249.6. Any biennial review of the rates, terms, and conditions for
any service of a Phase II Utility occurring in 2015 during the Transitional
Rate Period shall be solely a review of the utility's earnings on its rates for
generation and distribution services for the two 12-month test periods ending
December 31, 2014, and a determination of whether any credits to customers are
due for such test periods pursuant to subdivision A 8 b of §56-585.1. After
the conclusion of the Transitional Rate Period, biennial reviews
of the utility's rates for generation and
distribution services shall resume for a Phase I Utility in 2020,
with the first such proceeding utilizing the two successive 12-month test
periods beginning January 1, 2018, and ending December 31, 2019. After the
conclusion of the Transitional Rate Period, biennial reviews
of the utility's rates for generation and
distribution services shall resume for a Phase II Utility,
as defined in §56-585.1, in 20222021,
with the first such proceeding utilizing the two three
successive 12-month test periods beginning January 1, 20202018,
and ending December 31, 20212020.
Consistent with this provision, (i) no biennial review filings shall be made by
an investor-owned incumbent electric utility in the years 2016 through 2019,
inclusive, and (ii) no adjustment to an investor-owned incumbent electric
utility's existing tariff rates, including any rates adopted pursuant to §
56-235.2, shall be made between the beginning of the Transitional Rate Period
and the conclusion of the first biennial review
after the conclusion of the Transitional Rate Period, except as may be provided
pursuant to §56-245 or 56-249.6 or subdivisions A 4, 5, or 6 of §56-585.1.
B. During the Transitional Rate Period, pursuant to §56-36, the Commission shall have the right at all times to inspect the books, papers and documents of any investor-owned incumbent electric utility and to require from such companies, from time to time, special reports and statements, under oath, concerning their business.
C. 1. Commencing in 2016 and concluding in 2018, the State Corporation Commission, after notice and opportunity for a hearing, shall conduct a proceeding every two years to determine the fair rate of return on common equity to be used by a Phase I Utility as the general rate of return applicable to rate adjustment clauses under subdivisions A 5 or A 6 of § 56-585.1. A Phase I Utility's filing in such proceedings shall be made on or before March 31 of 2016, and 2018.
2. Commencing in 2017 and concluding in 2019, the State Corporation Commission, after notice and opportunity for a hearing, shall conduct a proceeding every two years to determine the fair rate of return on common equity to be used by a Phase II Utility as the general rate of return applicable to rate adjustment clauses under subdivisions A 5 or A 6 of § 56-585.1. A Phase II utility's filing in such proceedings shall be made on or before March 31 of 2017 and 2019.
3. Such fair rate of return shall be calculated pursuant to
the methodology set forth in subdivisions A 2 a and b of §56-585.1 and shall
utilize the utility's actual end-of-test-period capital structure and cost of
capital, as well as a 12-month test period ending December 31 immediately
preceding the year in which the proceeding is conducted. The Commission's final
order in such a proceeding shall be entered no later than eight months after
the date of filing, with any adjustment to the fair rate of return for
applicable rate adjustment clauses under subdivisions A 5 and 6 of §56-585.1
taking effect on the date of the Commission's final order in the proceeding,
utilizing rate adjustment clause true-up protocols as the Commission may in its
discretion determine. Such proceeding shall concern only the issue of the
determination of such fair rate of return to be used for rate adjustment
clauses under subdivisions A 5 and 6 of §56-585.1, and such determination
shall have no effect on rates other than those applicable to such rate adjustment
clauses; however, after the final such proceeding for a utility has been
concluded, the fair combined rate of return on common equity so determined
therein shall also be deemed equal to the fair combined rate of return on
common equity to be used in such utility's first biennial review
proceeding conducted after the end of the utility's Transitional Rate Period to
review such utility's earnings on its rates for generation and distribution
services for the historic test periods.
D. In furtherance of rate stability during the Transitional Rate Period, any Phase II Utility carrying a prior period deferred fuel expense recovery balance on its books and records as of December 31, 2014, shall not recover from customers 50 percent of any such balance outstanding as of December 31, 2014, and the State Corporation Commission shall implement as soon as practicable reductions in the fuel factor rate of any such Phase II Utility to reflect the nonrecovery of any such fuel expense as well as any reduction in the fuel factor associated with the Phase II Utility's current period forecasted fuel expense over recovery for the 2014-2015 fuel year and projected fuel expense for the 2015-2016 fuel year.
E. Except for early retirement plans identified by the utility in an integrated resource plan filed with the State Corporation Commission by September 1, 2014, for utility generation plants, an investor-owned incumbent electric utility shall not permanently retire an electric power generation facility from service during the Transitional Rate Period without first obtaining the approval of the State Corporation Commission, upon petition from such investor-owned incumbent electric utility, and a finding by the State Corporation Commission that the retirement determination is reasonable and prudent. During the Transitional Rate Period, an investor-owned incumbent electric utility shall recover the following costs, as recorded per books by the utility for financial reporting purposes and accrued against income, only through its existing tariff rates for generation or distribution services, except such costs as may be recovered pursuant to §56-245, §56-249.6 or subdivisions A 4, A 5, or A 6 of §56-585.1: (i) costs associated with asset impairments related to early retirement determinations for utility generation facilities resulting from the implementation of carbon emission guidelines for existing electric power generation facilities that the U.S. Environmental Protection Agency has issued pursuant to §111(d) of the Clean Air Act; (ii) costs associated with severe weather events; and (iii) costs associated with natural disasters.
F. During the Transitional Rate Period:
1. The State Corporation Commission shall submit a report and make recommendations to the Governor and the General Assembly annually on or before December 1 of each year assessing the updated integrated resource plan of any investor-owned incumbent electric utility. The report shall include an analysis of, among other matters, the amount, reliability, and type of generation facilities needed to serve Virginia native load compared to what is then available to serve such load and what may be available to serve such load in the future in view of market conditions and current and pending state and federal environmental regulations. As a part of such report, the State Corporation Commission shall update its estimate of the impact upon electric rates in Virginia of the implementation of carbon emission guidelines for existing electric power generation facilities that the U.S. Environmental Protection Agency has issued pursuant to §111(d) of the federal Clean Air Act. The State Corporation Commission shall submit copies of such annual reports to the Chairmen of the House and Senate Committees on Commerce and Labor and the Chairman of the Commission on Electric Utility Regulation; and
2. The Department of Environmental Quality shall submit a report and make recommendations to the Governor and the General Assembly annually on or before December 1 of each year concerning the implementation of carbon emission guidelines for existing electric power generation facilities that the U.S. Environmental Protection Agency has issued pursuant to §111(d) of the federal Clean Air Act. The report shall include an analysis of, among other matters, the impact of such federal regulations on the operation of any investor-owned incumbent electric utility's electric power generation facilities and any changes, interdiction, or suspension of such regulations. The Department of Environmental Quality shall submit copies of such annual reports to the Chairmen of the House and Senate Committees on Commerce and Labor and the Chairman of the Commission on Electric Utility Regulation.
G. The construction or purchase by an investor-owned incumbent
utility of one or more generation facilities with at least one megawatt of
generating capacity, and with an aggregate rated capacity that does not exceed 500
4,000 megawatts, including rooftop
solar installations with a capacity of not less than 50 kilowatts, and with an
aggregate capacity of 50 megawatts, that use energy derived from
sunlight and are located in the Commonwealth, regardless of whether any of such
facilities are located within or without such utility's service territory, is
in the public interest, and in determining whether to approve such facility,
the Commission shall liberally construe the provisions of this section. Such
utility shall utilize goods or services sourced, in whole or in part, from one
or more Virginia businesses. The utility may propose a rate adjustment clause
based on a market index in lieu of a cost of service model for such facility.
An investor-owned incumbent utility may enter into short-term or long-term
power purchase contracts for the power derived from sunlight generated by such
generation facility prior to purchasing the generation facility.
H. To the extent the provisions of this section are inconsistent with the provisions of §§56-249.6 and 56-585.1, the provisions of this section shall control.
2. §1. There is hereby established a pilot program to further the understanding of underground electric transmission lines in regard to electric reliability, construction methods and related cost and timeline estimating, and the probability of meeting such projections. The pilot program shall consist of the approval to construct qualifying electrical transmission lines of 230 kilovolts or less (but greater than 69 kilovolts) in whole or in part underground. Such pilot program shall consist of a total of two qualifying electrical transmission line projects, constructed in whole or in part underground, as specified and set forth in this act.
§2. Notwithstanding any other law to the contrary, as a part of the pilot program established pursuant to this Act, the State Corporation Commission shall approve as a qualifying project a transmission line of 230 kilovolts or less that is pending final approval of a certificate of public convenience and necessity from the State Corporation Commission as of December 31, 2017, for the construction of an electrical transmission line approximately 5.3 miles in length utilizing both overhead and underground transmission facilities, of which the underground portion shall be approximately 3.1 miles in length, which has been previously proposed for construction within or immediately adjacent to the right of way of an interstate highway. Once the State Corporation Commission has affirmed the project need through a final order, the project shall be constructed in part underground, and the underground portion shall consist of a double circuit.
The State Corporation Commission shall approve such underground construction within 30 days of receipt of the written request of the public utility to participate in the pilot program pursuant to this section. The State Corporation Commission shall not require the submission of additional technical and cost analyses as a condition of its approval, but may request such analyses for its review. The State Corporation Commission shall approve the underground construction of one contiguous segment of the transmission line that is approximately 3.1 miles in length that was previously proposed for construction within or immediately adjacent to the right of way of the interstate highway, which, by resolution, the city/locality has indicated general community support. The remainder of the construction for the transmission line shall be aboveground. The Commission shall not be required to perform any further analysis as to the impacts of this route, including environmental impacts or impacts upon historical resources.
The electric utility may proceed to acquire right of way and take such other actions as it deems appropriate in furtherance of the construction of the approved transmission line, including acquiring the cables necessary for the underground installation.
§3. In reviewing applications submitted by public utilities for certificates of public convenience and necessity for the construction of electrical transmission lines of 230 kilovolts or less filed between the effective date of this Act and July 1, 2020, the State Corporation Commission shall approve, consistent with the requirements of §4 of this enactment, one additional application as a qualifying project to be constructed in whole or in part underground, as a part of this pilot program. The one qualifying project shall be in addition to the qualifying project described in §2 of this enactment.
§4. For purposes of §3, a project shall be qualified to be placed underground, in whole or in part, if it meets all of the following criteria: (i) an engineering analysis demonstrates that it is technically feasible to place the proposed line, in whole or in part, underground; (ii) the governing body of each locality in which a portion of the proposed line will be placed underground indicates, by resolution, general community support for the project and that it supports the transmission line to be placed underground; (iii) a project has been filed with the State Corporation Commission or is pending issuance of a certificate of public convenience and necessity by July 1, 2020; (iv) the estimated additional cost of placing the proposed line, in whole or in part, underground does not exceed 2.5 times the cost of placing the same line overhead, assuming accepted industry standards for undergrounding to ensure safety and reliability; if the public utility, the affected localities, and the State Corporation Commission agree, a proposed underground line whose cost exceeds 2.5 times the cost of placing the line overhead may also be accepted into the pilot program; (v) the public utility requests that the project be considered as a qualifying project under this enactment; and, (vi) the primary need of the project shall be for purposes of grid reliability, grid resiliency, or to support economic development priorities of the Commonwealth and shall not be to address aging assets that would have otherwise been replaced in due course.
§5. Approval of a transmission line pursuant to this enactment for inclusion in the pilot program shall be deemed to satisfy the requirements of §15.2-2232 and local zoning ordinances with respect to such transmission line and any associated facilities, such as stations, substations, transition stations and locations, and switchyards or stations, that may be required.
§6. The State Corporation Commission shall report annually to the Commission on Electric Utility Restructuring, the Joint Commission on Technology and Science, and the Governor on the progress of the pilot program by no later than December 1 of each year that this act is in effect. The State Corporation Commission shall submit a final report to the Commission on Electric Utility Restructuring, the Joint Commission on Technology and Science, and the Governor no later than December 1, 2024, analyzing the entire program and making recommendations about the continued placement of transmission lines underground in the Commonwealth. The State Corporation Commission's final report shall include, but not limited to, analysis and findings of the costs of underground construction and historical and future consumer rate effects of such costs, effect of underground transmission lines on grid reliability, operability (including operating voltage), probability of meeting cost and construction timeline estimates of such underground transmission lines, and aesthetic or other benefits attendant to the placement of transmission lines underground.
§7. For the qualifying projects chosen pursuant to this enactment and not fully recoverable as charges for new transmission facilities pursuant to subdivision A 4 of §56-585.1, the State Corporation Commission shall approve a rate adjustment clause. The rate adjustment clause shall provide for the full and timely recovery of any portion of the cost of such project not recoverable under applicable rates, terms, and conditions approved by the Federal Energy Regulatory Commission and shall include the use of the fair return on common equity most recently approved in a State Corporation Commission proceeding for such utility. Such costs shall be entirely assigned to the utility's Virginia jurisdictional customers. The State Corporation Commission's final order regarding any petition filed pursuant to this subsection shall be entered not more than three months after the filing of such petition.
§8. Approval of a proposed transmission line for inclusion in this program shall not preclude the placing of existing or future overhead facilities in the same area or corridor by other transmission projects.
§9. The provisions of this enactment shall not be construed to limit the ability of the State Corporation Commission to approve additional applications for placement of transmission lines underground.
§10. If two applications are not submitted to the State Corporation Commission that meet the requirements of this act, the State Corporation Commission shall document the failure of the projects to qualify for the pilot program in order to justify approving fewer than two projects to be placed underground, in whole or in part.
§11. Insofar as the provisions of this act are inconsistent with the provisions of any other law or local ordinance, the provisions of this act shall be controlling.
3. That, no later than thirty (30) days following the effective date of this act, a Phase II Utility shall provide to its current customers a one-time, voluntary generation and distribution services bill credit, to be allocated on an historic test period energy usage basis, in an aggregate amount of $133 million. The one-time voluntary generation and distribution services bill credit shall not be included in any earnings test after the effective date of this act.
4. That any Phase II utility shall no longer recover from customers, as of the effective date of this act, any costs previously approved by the State Corporation Commission associated with major unit modifications to convert existing generation facilities to become operational as generation units utilizing biomass fuel through a rate adjustment clause pursuant to subdivision A 6 of §56-585.1, and shall, as of the effective date of this act, instead begin to recover any such remaining costs through the utility's rates for generation and distribution services, with no change in such rates for generation and distribution services as a result of the combination of such costs with the other costs, revenues and investments included in its rates for generation and distribution services. Any such costs shall remain combined with the utility's other costs, revenues and investments included in its rates for generation and distribution services until such costs are fully recovered.
5. That the State Corporation Commission shall implement reductions in the rates for generation and distribution services of incumbent electric utilities, as defined in §56-576, effective April 1, 2019, to reflect the actual annual reductions in corporate income taxes to be paid by such utilities pursuant to the provisions of the federal Tax Cuts and Jobs Act of 2017 (Public Law 115-97).
6. In advance of the determination of the State Corporation Commission as to rate reductions to reflect reductions in corporate income taxes pursuant to the fifth enactment of this act, any Phase II utility as defined in subdivision A 1 of §56-585.1 of the Code of Virginia shall reduce its existing rates for generation and distribution services on an interim basis, within thirty (30) days of the effective date of this act, in an amount sufficient to reduce its annual revenues from such rates by an aggregate amount of $125 million, provided, however, that such $125 million shall be reduced by the amount of any annual revenue requirement associated with any rate adjustment clause previously authorized pursuant to subdivision A 6 of §56-585.1 and relating to major unit modifications of generation facilities that utilize biomass fuel which are withdrawn as of the effective date of this act pursuant to the fourth enactment of this act. The net amount of such interim reduction in rates for generation and distribution services shall be attributable to reductions in the corporate income tax obligations of the utility pursuant to the provisions of the Federal Tax Cut and Jobs Act of 2017 (Public Law 115-97). In implementing any further reductions to the rates for generation and distribution services of any such Phase II Utility effective April 1, 2019, pursuant to the fifth enactment of this act, the Commission shall consider this interim revenue requirement reduction, and its actions shall be limited to a true-up of this interim reduction amount to the actual annual reduction in corporate tax obligations of such utility as of the effective date of this act.
7. That the provisions of this act amending and reenacting § 56-585.1 of the Code of Virginia by adding subdivision A 8 d shall expire on July 1, 2028.
8. That each Phase I and Phase II utility, as such terms are defined in subdivision A 1 of §56-585.1 of the Code of Virginia, shall continue, at no less than the existing levels of funding, as of the effective date of this act, the pilot programs established pursuant to Chapter 6 of the Acts of Assembly of 2015 for energy assistance and weatherization for low income, elderly, and disabled individuals in their respective service territories in the Commonwealth. Each such utility shall report on the status of its pilot program, including the number of individuals served thereby, to the Governor, the State Corporation Commission, and the Chairmen of the House and Senate Commerce and Labor Committees on July 1, 2019, and annually thereafter.
9. That this act shall be known as The Grid Modernization and Security Act.