Source: http://lis.virginia.gov/cgi-bin/legp604.exe?181+ful+SB967
Timestamp: 2019-01-22 17:34:35
Document Index: 330369584

Matched Legal Cases: ['§ 56', '§ 56', '§ 56', '§ 15', '§ 15', '§ 56', '§ 56', '§ 56', '§ 56', '§ 56', '§ 15', '§ 15', '§ 56', '§ 56', '§ 56', '§ 56', '§ 67', '§ 56', '§ 56', '§ 56', '§ 56', '§ 56', '§ 56', '§ 56', '§ 56', '§ 56', '§ 2', '§ 3', '§ 4', '§ 2', '§4', '§ 3', '§ 5', '§ 15', '§ 6', '§ 7', '§ 56', '§ 8', '§ 9', '§ 10', '§ 11', '§ 56', '§ 56', '§ 56', '§ 56', '§ 56']

18105575D
SENATE BILL NO. 967 Offered January 19, 2018 A BILL to amend and reenact §§ 56-265.1, 56-466.2, 56-576, 56-585.1, and 56-585.1:1 of the Code of Virginia, relating to electric utility regulation; grid modernization; energy efficiency programs; schedule for rate review proceedings; Transitional Rate Period; energy storage facilities; electric distribution grid transformation projects, wind and solar generation facilities; coal combustion by-product management; pilot programs; undergrounding electrical transmission lines; fuel factor; bill credits; rate adjustment clauses for major unit conversions; rate reductions attributable to changes in federal tax law. ---------- Patron-- Saslaw ---------- Referred to Committee on Commerce and Labor ----------
1. That §§ 56-265.1, 56-466.2, 56-576, 56-585.1, and 56-585.1:1 of the Code of Virginia are amended and reenacted as follows:
When an investor-owned incumbent electric utility proposes to improve electric service reliability pursuant to clause (iv) of subdivision A 6 of § 56-585.1 by installing new underground facilities to replace the utility's existing overhead distribution tap lines, if the utility owns the poles from which the existing overhead distribution tap lines are to be relocated and any cable operator of a cable television system, as those terms are defined in § 15.2-2108.19, has also attached its facilities to such poles, the utility shall provide written notice to the cable operator of the utility's intention to relocate the overhead distribution tap lines and to abandon or remove such poles not less than 90 days prior to relocating the utility's overhead distribution lines. The cable operator shall notify the utility within 45 days of the notice of relocation whether the cable operator will relocate its facilities underground or request to remain overhead in accordance with the provisions set forth herein. If the cable operator elects to relocate its facilities underground, in such notice the cable operator may request that the utility use commercially reasonable efforts to negotiate a common shared underground easement for the facilities to be located underground of the utility and the cable operator. The cable operator shall be responsible to negotiate any additional easements that it may require. If the cable operator elects to relocate its facilities underground, the cable operator may participate with the utility in a joint relocation of the overhead lines to underground or may engage its own contractors to undertake its relocation work if it deems it appropriate to do so. If the cable operator may legally retain the poles that the utility intends to abandon and the cable operator wishes for its facilities to remain attached to the poles, the utility may convey such poles "as-is" and "where-is" to the cable operator at its depreciated cost less the estimated cost of removal, provided the cable operator assumes all liability for the pole and obtains an easement from the property owner for the use thereof on or before the date the poles are conveyed to the cable operator. In all cases, the cable operator shall be responsible for all costs related to the relocation of cable facilities and, unless otherwise agreed between the utility and the cable operator, the cable operator shall cease all use of such poles and shall relocate or remove its facilities from the poles on or before 90 days after the utility gives written notice to the cable operator that it has relocated its distribution tap lines underground. The utility shall not abandon or remove the poles that the utility owns until the cable operator completes the relocation or removal of its facilities or 90 days after the completion of the relocation of the utility overhead distribution lines, whichever first occurs. If the cable operator does not elect to relocate its facilities underground and requests to maintain its facilities overhead, the utility may either (i) convey such poles "as-is" and "where-is" to the cable operator at its depreciated cost less the estimated cost of removal, provided the cable operator may legally retain the poles that the utility intends to abandon and assumes all liability for the poles conveyed or (ii) retain ownership of its poles and allow the cable operator's existing overhead facilities to remain attached in which case the utility shall maintain the pole in accordance with prudent utility standards provided that the cable operator shall continue to pay its pole attachment fees and otherwise comply with its contractual obligations pursuant to the applicable pole attachment agreement. In all cases, the cable operator shall be responsible for all costs related to the relocation or maintenance of its facilities.
In instances in which an investor-owned incumbent electric utility continues to own and maintain its utility poles after the overhead distribution lines of the utility formerly on such poles have been placed underground pursuant to the foregoing provisions, then for purposes of any agreement or ordinance with respect to a cable franchise under §§ 15.2-2108.20 or 15.2-2108.21, the utility shall not be deemed to have converted to underground.
"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.
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.
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.
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 4,000 megawatts, including rooftop solar installations with a capacity of not less than 50 kilowatts, and with an aggregate capacity of 50 megawatts, that use energy derived from sunlight and are located in the Commonwealth, regardless of whether any of such facilities are located within or without the utility's service territory, is in the public interest, and in determining whether to approve such facility, the Commission shall liberally construe the provisions of this title. A utility may enter into short-term or long-term power purchase contracts for the power derived from sunlight generated by such generation facility prior to purchasing the generation facility. The replacement of any subset of a utility's existing overhead distribution tap lines that have, in the aggregate, an average of nine or more total unplanned outage events-per-mile over a preceding 10-year period with new underground facilities in order to improve electric service reliability is in the public interest. In determining whether to approve petitions for rate adjustment clauses for such new underground facilities that meet this criteria, and in determining the level of costs to be recovered thereunder, the Commission shall liberally construe the provisions of this title. There shall be a rebuttable presumption that the The conversion of any such facilities will on or after September 1, 2016, is deemed to provide local and system-wide benefits, that such new underground facilities are and to be cost beneficial, and that the costs associated with such new underground facilities are deemed to be reasonably and prudently incurred and shall be approved for recovery by the Commission pursuant to this subdivision provided that the total costs associated with the replacement of any subset of existing overhead distribution tap lines proposed by the utility with new underground facilities, exclusive of financing costs, shall not exceed an average cost per customer of $20,000, with such customers including those served directly by or downline of the tap lines proposed for conversion and, further, such total costs shall not exceed an average cost per mile of tap lines converted, exclusive of financing costs, of $750,000. A utility may, without regard for whether it has petitioned for any rate adjustment clause pursuant to clause (vi), petition the Commission, not more than once annually, for approval of a plan for electric distribution grid transformation projects. In ruling upon such a petition, the Commission shall consider whether the utility’s plan for such projects, and the projected costs associated therewith, are reasonable and prudent. Such petition shall be considered on a stand-alone basis without regard to the other costs, revenues, investments or earnings of the utility, without regard to whether the costs associated with such projects will be recovered through a rate adjustment clause under this subdivision or through the utility’s rates for generation and distribution services, and without regard to whether such costs will be the subject of a customer credit offset, as applicable, pursuant to subdivision 8 d. The Commission’s final order regarding any such petition for approval of an electric distribution grid transformation plan shall be entered by the Commission not more than six months after the date of filing such petition. The Commission shall likewise enter its final order with respect to any petition by a utility for a certificate to construct and operate a generating facility or facilities utilizing energy derived from sunlight, pursuant to § 56-580.D of this chapter, within six months after the date of filing such petition. The basis points to be added to the utility's general rate of return to calculate the enhanced rate of return on common equity, and the first portion of that facility's service life to which such enhanced rate of return shall be applied, shall vary by type of facility, as specified in the following table:
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.
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.
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. 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.
A. No biennial reviews of the rates, terms, and conditions for any service of a Phase I Utility, as defined in § 56-585.1, shall be conducted at any time by the State Corporation Commission for the four successive 12-month test periods beginning January 1, 2014, and ending December 31, 2017. No biennial reviews of the rates, terms, and conditions for any service of a Phase II Utility, as defined in § 56-585.1, shall be conducted at any time by the State Corporation Commission for the five three successive 12-month test periods beginning January 1, 2015, and ending December 31, 20192017. Such test periods beginning January 1, 2014, and ending December 31, 2017, for a Phase I Utility, and beginning January 1, 2015, and ending December 31, 20192017, for a Phase II Utility, are collectively referred to herein as the "Transitional Rate Period." Review of recovery of fuel and purchase power costs shall continue during the Transitional Rate Period in accordance with § 56-249.6. Any biennial review of the rates, terms, and conditions for any service of a Phase II Utility occurring in 2015 during the Transitional Rate Period shall be solely a review of the utility's earnings on its rates for generation and distribution services for the two 12-month test periods ending December 31, 2014, and a determination of whether any credits to customers are due for such test periods pursuant to subdivision A 8 b of § 56-585.1. After the conclusion of the Transitional Rate Period, biennial reviews of the utility's rates for generation and distribution services shall resume for a Phase I Utility in 2020, with the first such proceeding utilizing the two successive 12-month test periods beginning January 1, 2018, and ending December 31, 2019. After the conclusion of the Transitional Rate Period, biennial reviews of the utility's rates for generation and distribution services shall resume for a Phase II Utility, as defined in § 56-585.1, in 20222021, with the first such proceeding utilizing the two three successive 12-month test periods beginning January 1, 20202018, and ending December 31, 20212020. Consistent with this provision, (i) no biennial review filings shall be made by an investor-owned incumbent electric utility in the years 2016 through 2019, inclusive, and (ii) no adjustment to an investor-owned incumbent electric utility's existing tariff rates, including any rates adopted pursuant to § 56-235.2, shall be made between the beginning of the Transitional Rate Period and the conclusion of the first biennial review after the conclusion of the Transitional Rate Period, except as may be provided pursuant to § 56-245 or 56-249.6 or subdivisions A 4, 5, or 6 of § 56-585.1.
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. 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.
§ 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.
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.
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.