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2018 SESSION
18105626DBe 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.
"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
beginning January 1, 2018, and 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 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 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.
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 2022,2021,
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 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. 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 (a) the reliability of electrical transmission or distribution systems; (b) the integration of utility or customer owned renewable electric generation resources with the utility’s electric distribution grid; (c) the level of investment in generation, transmission, or distribution of electricity; (d) the need for additional generation of electricity during times of peak demand; and (e) distribution system hardening projects and enhanced physical security measures. 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.
10. That this act shall be known as The Grid Modernization and Security Act.