(a)(1) A “least-cost integrated plan” for a regulated electric or gas utility is a plan for meeting the public’s need for energy services, after safety concerns are addressed, at the lowest present value life cycle cost, including environmental and economic costs, through a strategy combining investments and expenditures on energy supply, transmission, and distribution capacity, transmission and distribution efficiency, and comprehensive energy efficiency programs. Economic costs shall be assessed with due regard to:
(A)the greenhouse gas inventory developed under the provisions of 10 V.S.A. § 582;
(B)the State’s progress in meeting its greenhouse gas reduction goals;
(C)the value of the financial risks associated with greenhouse gas emissions from various power sources; and
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(a)(1) A “least-cost integrated plan” for a regulated electric or gas utility is a plan for meeting the public’s need for energy services, after safety concerns are addressed, at the lowest present value life cycle cost, including environmental and economic costs, through a strategy combining investments and expenditures on energy supply, transmission, and distribution capacity, transmission and distribution efficiency, and comprehensive energy efficiency programs. Economic costs shall be assessed with due regard to:
(A) the greenhouse gas inventory developed under the provisions of 10 V.S.A. § 582;
(B) the State’s progress in meeting its greenhouse gas reduction goals;
(C) the value of the financial risks associated with greenhouse gas emissions from various power sources; and
(D) consistency with section 8001 (renewable energy goals) of this title.
(2) “Comprehensive energy efficiency programs” shall mean a coordinated set of investments or program expenditures made by a regulated electric or gas utility or other entity as approved by the Commission pursuant to subsection 209(d) of this title to meet the public’s need for energy services through efficiency, conservation, or load management in all customer classes and areas of opportunity that is designed to acquire the full amount of cost-effective savings from such investments or programs.
(b) Each regulated electric or gas company shall prepare and implement a least-cost integrated plan for the provision of energy services to its Vermont customers. At least every third year on a schedule directed by the Public Utility Commission, each such company shall submit a proposed plan to the Department of Public Service and the Public Utility Commission. The Commission, after notice and opportunity for hearing, may approve a company’s least-cost integrated plan if it determines that the company’s plan complies with the requirements of subdivision (a)(1) of this section and of sections 8004 and 8005 of this title and is consistent with the goals of the Comprehensive Energy Plan issued under section 202b of this title.
(c) [Repealed.]
(d)(1) Least-cost transmission services shall be provided in accordance with this subsection. On or before July 1, 2006, any electric company that does not have a designated retail service territory and that owns or operates electric transmission facilities within the State of Vermont, in conjunction with any other electric companies that own or operate these facilities, jointly shall prepare and file with the Department of Public Service and the Public Utility Commission a Transmission System Plan that looks forward for a period of at least 10 years. A copy of the plan shall be filed with each of the following: the House Committees on Commerce and Economic Development and on Environment and Energy and the Senate Committees on Finance and on Natural Resources and Energy. The objective of the Plan shall be to identify the potential need for transmission system improvements as early as possible, in order to allow sufficient time to plan and implement more cost-effective nontransmission alternatives to meet reliability needs, wherever feasible. The Plan shall:
(A) identify existing and potential transmission system reliability deficiencies by location within Vermont;
(B) estimate the date, and identify the local or regional load levels and other likely system conditions at which these reliability deficiencies, in the absence of further action, would likely occur;
(C) describe the likely manner of resolving the identified deficiencies through transmission system improvements;
(D) estimate the likely costs of these improvements;
(E) identify potential obstacles to the realization of these improvements; and
(F) identify the demand or supply parameters that generation, demand response, energy efficiency, or other nontransmission strategies would need to address to resolve the reliability deficiencies identified.
(2) Prior to the adoption of any Transmission System Plan, a utility preparing a Plan shall host at least two public meetings at which it shall present a draft of the Plan and facilitate a public discussion to identify and evaluate nontransmission alternatives. The meetings shall be at separate locations within the State, in proximity to the transmission facilities involved or as otherwise required by the Commission, and each shall be noticed by at least two advertisements, each occurring between one and three weeks prior to the meetings, in newspapers having general circulation within the State and within the municipalities in which the meetings are to be held. Copies of the notices shall be provided to the Public Utility Commission, the Department of Public Service, any entity appointed by the Public Utility Commission pursuant to subdivision 209(d)(2) of this title, the Agency of Natural Resources, the Division for Historic Preservation, the Department of Health, the Agency of Transportation, the Attorney General, the chair of each regional planning commission, each retail electricity provider within the State, and any public interest group that requests, or has made a standing request for, a copy of the notice. A verbatim transcript of the meetings shall be prepared by the utility preparing the Plan, shall be filed with the Public Utility Commission and the Department of Public Service, and shall be provided at cost to any person requesting it. The Plan shall contain a discussion of the principal contentions made at the meetings by members of the public, by any State agency, and by any utility.
(3) Prior to the issuance of the Transmission Plan or any revision of the Plan, the utility preparing the Plan shall offer to meet with each retail electricity provider within the State, with any entity appointed by the Public Utility Commission pursuant to subdivision 209(d)(2) of this title, and with the Department of Public Service, for the purpose of exchanging information that may be relevant to the development of the Plan.
(4)(A) A Transmission System Plan shall be revised:
(i) within nine months of a request to do so made by either the Public Utility Commission or the Department of Public Service; and
(ii) in any case, at intervals of not more than three years.
(B) If more than 18 months shall have elapsed between the adoption of any version of the Plan and the next revision of the Plan, or since the last public hearing to address a proposed revision of the Plan and facilitate a public discussion that identifies and evaluates nontransmission alternatives, the utility preparing the Plan, prior to issuing the next revision, shall host public meetings as provided in subdivision (2) of this subsection, and the revision shall contain a discussion of the principal contentions made at the meetings by members of the public, by any State agency, and by any retail electricity provider.
(5) On the basis of information contained in a Transmission System Plan, obtained through meetings held pursuant to subdivision (2) of this subsection, or obtained otherwise, the Public Utility Commission and the Department of Public Service shall use their powers under this title to encourage and facilitate the resolution of reliability deficiencies through nontransmission alternatives, where those alternatives would better serve the public good. The Public Utility Commission, upon such notice and hearings as are otherwise required under this title, may enter such orders as it deems necessary to encourage, facilitate, or require the resolution of reliability deficiencies in a manner that it determines will best promote the public good.
(6) The retail electricity providers in affected areas shall incorporate the most recently filed Transmission Plan in their individual least-cost integrated planning processes, and shall cooperate as necessary to develop and implement joint least-cost solutions to address the reliability deficiencies identified in the Transmission Plan.
(7) Before the Department of Public Service takes a position before the Commission concerning the construction of new transmission or a transmission upgrade with significant land use ramifications, the Department shall hold one or more public meetings with the legislative bodies or their designees of each town, village, or city that the transmission lines cross and shall engage in a discussion with the members of those bodies or their designees and the interested public as to the Department’s role as public advocate. (Added 1991, No. 99, § 2; amended 1999, No. 60, § 2, eff. June 1, 1999; 1999, No. 157 (Adj. Sess.), § 7; 2005, No. 61, § 9; 2007, No. 209 (Adj. Sess.), § 13; 2011, No. 62, § 25; 2011, No. 170 (Adj. Sess.), § 11; 2015, No. 40, § 30; 2015, No. 56, § 17; 2017, No. 113 (Adj. Sess.), § 173b; 2017, No. 139 (Adj. Sess.), § 9.)