1st Unofficial Engrossment - 82nd Legislature (2001 - 2002) Posted on 12/15/2009 12:00am
1.1 A bill for an act 1.2 relating to energy; enacting the Minnesota Energy 1.3 Security and Reliability Act; requiring an energy 1.4 security blueprint and a state transmission plan; 1.5 establishing position of reliability administrator; 1.6 providing for essential energy infrastructure; 1.7 modifying provisions for siting, routing, and 1.8 determining the need for large electric power 1.9 facilities; regulating conservation expenditures by 1.10 energy utilities and eliminating state pre-approval of 1.11 conservation plans by public utilities; encouraging 1.12 regulatory flexibility in supplying and obtaining 1.13 energy; regulating interconnection of distributed 1.14 utility resources; providing for safety and service 1.15 standards from distribution utilities; clarifying the 1.16 state cold weather disconnection requirements; 1.17 authorizing municipal utilities, municipal power 1.18 agencies, cooperative utilities, and investor-owned 1.19 utilities to form joint ventures to provide utility 1.20 services; eliminating the requirement for individual 1.21 utility resource plans; requiring reports; making 1.22 technical, conforming, and clarifying changes; 1.23 amending Minnesota Statutes 2000, sections 116.07, 1.24 subdivision 4a; 116C.52, subdivision 10; 116C.53, 1.25 subdivisions 2, 3; 116C.57, subdivisions 1, 2, 4, by 1.26 adding subdivisions; 116C.58; 116C.59, subdivisions 1, 1.27 4; 116C.60; 116C.61, subdivision 1; 116C.62; 116C.64; 1.28 116C.645; 116C.65; 116C.66; 116C.69; 216A.03, 1.29 subdivision 3a; 216B.095; 216B.097, subdivision 1; 1.30 216B.16, subdivisions 7, 15; 216B.2421, subdivision 2, 1.31 by adding a subdivision; 216B.2422, subdivision 2; 1.32 216B.243, subdivisions 2, 3, 4, by adding a 1.33 subdivision; 216C.051, subdivision 9; 216C.41, 1.34 subdivision 5, by adding a subdivision; proposing 1.35 coding for new law in Minnesota Statutes, chapters 1.36 116C; 216B; 216C; 452; repealing Minnesota Statutes 1.37 2000, sections 116C.55; 116C.57, subdivisions 3, 5, 1.38 5a; 116C.67; 216B.241; 216C.18. 1.39 BE IT ENACTED BY THE LEGISLATURE OF THE STATE OF MINNESOTA: 1.40 ARTICLE 1 1.41 ENERGY PLANNING 1.42 Section 1. [TITLE.] 2.1 This act shall be known as the Minnesota Energy Security 2.2 and Reliability Act. 2.3 Sec. 2. [216B.012] [STATE TRANSMISSION PLAN.] 2.4 Subdivision 1. [PLAN.] The commission shall maintain a 2.5 state transmission plan, consisting of a list of certified high 2.6 voltage transmission line projects. 2.7 Subd. 2. [PLAN DEVELOPMENT.] (a) By November 1 of each 2.8 odd-numbered year, each public utility, municipal utility, and 2.9 cooperative electric association, or the generation and 2.10 transmission organization that serves each utility or 2.11 association, that owns or operates electric transmission lines 2.12 in Minnesota shall jointly or individually submit a transmission 2.13 projects report to the commission. The report must: 2.14 (1) list specific present and reasonably foreseeable future 2.15 inadequacies in the transmission system in Minnesota; 2.16 (2) identify alternative means of addressing each 2.17 inadequacy listed; 2.18 (3) identify general economic, environmental, and social 2.19 issues associated with each alternative; and 2.20 (4) provide a summary of public input the utilities and 2.21 associations have gathered related to the list of inadequacies 2.22 and the role of local government officials and other interested 2.23 persons in assisting to develop the list and analyze 2.24 alternatives. 2.25 (b) To meet the requirements of this subdivision, entities 2.26 may rely on available information and analysis developed by a 2.27 regional transmission organization or any subgroup of a regional 2.28 transmission organization and may develop and include additional 2.29 information as necessary. A regional energy infrastructure 2.30 planning report issued under section 216B.019 and submitted 2.31 under this subdivision satisfies the requirements of this 2.32 subdivision for the member utilities. 2.33 Subd. 3. [COMMISSION APPROVAL.] By June 1 of each 2.34 even-numbered year, the commission shall adopt a state 2.35 transmission plan and shall certify, certify as modified, or 2.36 deny certification of the projects proposed under subdivision 3.1 2. The commission may only certify a project that is a high 3.2 voltage transmission line as defined in section 216B.2421, 3.3 subdivision 2, that the commission finds is: 3.4 (1) necessary to maintain or enhance the reliability of 3.5 electric service to Minnesota consumers; 3.6 (2) needed, applying the criteria in section 216B.241, 3.7 subdivision 3; 3.8 (3) a public purpose project, applying the considerations 3.9 in section 216B.241, subdivision 2a; and 3.10 (4) in the public interest, taking into account electric 3.11 energy system needs and economic, environmental, and social 3.12 interests affected by the project. 3.13 Projects certified as part of the state transmission plan 3.14 need no further review by the commission under section 3.15 216B.243. The reliability administrator shall provide technical 3.16 assistance to the commissioner and the commission in reviewing 3.17 the proposed projects. 3.18 Subd. 4. [CONTINUING OBLIGATION.] Each public utility, 3.19 municipal utility, and cooperative electric association that 3.20 operates and provides electric service in this state has an 3.21 existing and continuing obligation to provide reliable, 3.22 affordable, safe, and efficient services to their customers in 3.23 the state; to plan to meet the resource and infrastructure needs 3.24 of those customers; and to ensure that those resources and 3.25 infrastructure are sited and constructed, or otherwise acquired. 3.26 Sec. 3. [216B.013] [EXISTING GENERATION FACILITIES.] 3.27 In order to continue the low-maintenance and low-cost 3.28 service that the existing base-load generation facilities in 3.29 Minnesota have provided to Minnesota consumers, and to provide 3.30 power to meet the growing demand for electricity by Minnesota 3.31 consumers and businesses, it is the policy of the state that 3.32 these facilities be maintained and upgraded consistent with 3.33 energy policy goals established pursuant to this chapter. The 3.34 public utilities commission, department, and other state 3.35 agencies with regulatory jurisdiction over the operation of 3.36 these facilities shall take all steps necessary to incorporate 4.1 this state policy into the regulatory decisions made by each 4.2 respective agency. 4.3 Sec. 4. [216B.014] [ENERGY SECURITY AND RELIABILITY.] 4.4 (a) It is a fundamental goal of Minnesota's energy and 4.5 utility policy that state policymakers maximize the state's 4.6 energy security. 4.7 (b) "Energy security" means, among other things, ensuring 4.8 that the state's energy sources are: 4.9 (1) diverse, including (i) traditional sources such as 4.10 coal, natural gas, waste-to-energy, and nuclear facilities, (ii) 4.11 renewable sources such as wind, biomass, and agricultural waste 4.12 generation, and (iii) high-efficiency, low-emissions distributed 4.13 generation sources such as fuel cells and microturbines; 4.14 (2) to the extent feasible, produced in the state utilizing 4.15 Minnesota's resources; 4.16 (3) environmentally sustainable; 4.17 (4) available to consumers at affordable and stable rates 4.18 or prices; and 4.19 (5) above all, reliable. "Reliable" means, among other 4.20 things, that adequate resources and infrastructure are in place, 4.21 and are planned for, to provide efficient, dependable, and 4.22 secure energy services to Minnesota consumers. 4.23 Sec. 5. [216B.015] [ENERGY SECURITY BLUEPRINT.] 4.24 (a) The commissioner shall develop a draft energy security 4.25 blueprint by December 15, 2001, and every four years thereafter. 4.26 The blueprint must: 4.27 (1) identify important trends and issues in energy supply, 4.28 consumption, conservation, and costs; 4.29 (2) set energy goals; and 4.30 (3) develop strategies to meet the goals. 4.31 (b) For the purposes of sections 216B.012 to 216B.019, the 4.32 terms: 4.33 (1) "electric utility" means an entity that is a public 4.34 utility; a cooperative electric association providing 4.35 generation, transmission, or distribution services; a municipal 4.36 utility; or a municipal power agency; and 5.1 (2) "energy utility" means an electric utility, or an 5.2 entity providing natural gas to retail consumers. 5.3 Sec. 6. [216B.016] [ENERGY BLUEPRINT CONTENTS.] 5.4 The energy blueprint must include: 5.5 (1) the amount and type of projected statewide energy 5.6 consumption over the next ten years; 5.7 (2) a determination of whether and the extent to which 5.8 existing and anticipated energy production and transportation 5.9 facilities will or will not be able to supply needed energy; 5.10 (3) a determination of the potential for conservation to 5.11 meet some or all of the projected need for energy; 5.12 (4) an assessment of the environmental impact of projected 5.13 energy consumption over the next ten years, prepared by the 5.14 commissioner of the pollution control agency in consultation 5.15 with other state agencies and other interested persons, with 5.16 strategies to mitigate those impacts; and 5.17 (5) benchmarks to measure and monitor supply adequacy and 5.18 infrastructure capacity, and to assess the overall reliability 5.19 of the state's electric system. 5.20 Sec. 7. [216B.017] [ENERGY GOALS.] 5.21 (a) The blueprint must recommend statewide goals and 5.22 recommend strategies to accomplish the following goals for: 5.23 (1) energy conservation and recovery; 5.24 (2) limiting adverse environmental emissions from the 5.25 generation of electric energy consumed in the state; 5.26 (3) production of electric energy consumed in the state 5.27 from renewable energy sources; 5.28 (4) deployment of distributed electric generation 5.29 technologies; 5.30 (5) ensuring that energy service is affordable and 5.31 available to all consumers in the state; 5.32 (6) minimizing the imposition of social costs on energy 5.33 consumers through energy rates or prices; and 5.34 (7) increasing the efficiency of the regulatory 5.35 infrastructure and reducing regulatory and administrative costs. 5.36 (b) The goals adopted in the blueprint may be onetime goals 6.1 or a series of goals to meet overall objectives. The 6.2 commissioner shall present these goals, and any associated 6.3 strategies that require changes to state law, to the legislature 6.4 for modification and approval. 6.5 Sec. 8. [216B.018] [BLUEPRINT DEVELOPMENT.] 6.6 Subdivision 1. [PUBLIC PARTICIPATION.] The commissioner 6.7 shall: 6.8 (1) invite public and stakeholder comment and participation 6.9 during blueprint development; and 6.10 (2) hold at least one public meeting on the proposed 6.11 blueprint in each energy infrastructure planning region of the 6.12 state after at least 30 days' public notice in the region. 6.13 Subd. 2. [NOTICE AND COMMENT; BLUEPRINT ISSUANCE.] The 6.14 commissioner shall provide notice of all public meetings to 6.15 discuss the proposed blueprint and allow opportunity for written 6.16 comment prior to issuing the final blueprint. After review by 6.17 the administrator, the commissioner shall publish the final 6.18 energy blueprint in the State Register within four months of 6.19 issuing the draft blueprint. 6.20 Sec. 9. [216B.019] [REGIONAL ENERGY INFRASTRUCTURE 6.21 PLANNING.] 6.22 Subdivision 1. [ESTABLISHING PLANNING REGIONS.] The 6.23 commission, after notice and opportunity for written comment, 6.24 shall establish geographic regional energy infrastructure 6.25 planning regions in the state by August 1, 2001. Planning 6.26 regions may coincide with existing subregional planning areas 6.27 used by the regional electric reliability or regional 6.28 transmission organization serving Minnesota. The commission 6.29 shall also request comments on and approve, or approve as 6.30 modified, each group's organizational, administrative, planning, 6.31 and voting structures. 6.32 Subd. 2. [PLANNING GROUP.] Each energy utility that 6.33 operates in an identified region shall participate in the 6.34 regional energy infrastructure planning group. Each regional 6.35 group must include as voting members an equal number of 6.36 representatives of energy utilities, and representatives from 7.1 counties in the identified region, appointed by the county board. 7.2 Subd. 3. [PUBLIC MEETINGS.] Each regional energy 7.3 infrastructure planning group shall hold public meetings within 7.4 the region on a regular basis, not less than twice a year, and 7.5 provide public notice at least 14 calendar days in advance of a 7.6 meeting. 7.7 Subd. 4. [REPORT.] By November 1, 2001, and every two 7.8 years thereafter, each regional energy infrastructure planning 7.9 group shall submit a report to the commissioner that: 7.10 (1) identifies inadequacies in electric generation and 7.11 transmission within the region including any deficiencies as 7.12 defined in subdivision 5; 7.13 (2) lists alternative ways to address identified 7.14 inadequacies, taking into account the provisions of the state 7.15 energy security blueprint; 7.16 (3) identifies potential general and, to the extent known, 7.17 specific economic, environmental, and social issues associated 7.18 with each alternative; and 7.19 (4) recommends alternatives to address identified 7.20 inadequacies and deficiencies that ensure the reliability and 7.21 security of the energy system in the region, while minimizing 7.22 environmental and social impacts. In making recommendations, 7.23 the planning group shall identify critical needs. For the 7.24 purposes of this clause, "critical needs" are those projects 7.25 that are necessary to maintain reliable electric service to 7.26 Minnesota consumers that meet or exceed the most stringent 7.27 applicable state or regional reliability standards. A regional 7.28 planning group may satisfy the requirement to issue an initial 7.29 report under this section by submitting the portion of the 7.30 Mid-Continent Area Power Pool transmission plan that affects the 7.31 region, with any analysis, comment, or narrative that the group 7.32 deems important. 7.33 Subd. 5. [DEFICIENCY.] (a) "Deficiency" means a condition, 7.34 or set of conditions, that, based on the utility's most recent 7.35 forecast or consistent with the transmission expansion plan of a 7.36 federally approved regional transmission organization or 8.1 regional reliability entity, may materially limit the adequacy 8.2 of electric supply, efficiency of electric service, or 8.3 reliability of electric service to an electric utility's 8.4 customers in the state that may require construction of a 8.5 generation or transmission project. 8.6 (b) Within 90 days of identifying a deficiency in its 8.7 system, an electric utility shall give notice of the deficiency 8.8 to at least: 8.9 (1) the members of affected regional energy infrastructure 8.10 planning groups; 8.11 (2) officials of potentially affected local governments; 8.12 and 8.13 (3) the commissioner and the independent reliability 8.14 administrator. 8.15 (c) Notice of deficiency must be made before submitting (1) 8.16 an application for a certificate of need under section 216B.243 8.17 or (2) a request for environmental review of an energy project 8.18 to any governmental entity. 8.19 Sec. 10. Minnesota Statutes 2000, section 216C.051, 8.20 subdivision 9, is amended to read: 8.21 Subd. 9. [EXPIRATION.] This section is repealed
March 15,8.22 2001June 30, 2003. 8.23 Sec. 11. [216C.052] [RELIABILITY ADMINISTRATOR.] 8.24 Subdivision 1. [POSITION ESTABLISHED IN 8.25 DEPARTMENT.] Recognizing the critical importance of adequate, 8.26 reliable, and environmentally sound energy services to the 8.27 state's economy and the well being of its citizens, and that 8.28 independent and expert technical analysis is necessary to ensure 8.29 the reliability of the energy system, the position of 8.30 reliability administrator is established within the department 8.31 of commerce. 8.32 Subd. 2. [RESPONSIBILITIES.] (a) The administrator shall 8.33 provide technical advice and assistance to the department, the 8.34 commission, and regional energy infrastructure planning groups. 8.35 In addition, the administrator shall provide technical and 8.36 administrative assistance to the legislative electric energy 9.1 task force. In conducting its work, the administrator shall: 9.2 (1) model and monitor the use and operation of the energy 9.3 infrastructure in the state, including generation facilities, 9.4 transmission lines, natural gas pipelines, and other energy 9.5 infrastructure; 9.6 (2) develop and present to the commission and parties 9.7 technical analyses of proposed infrastructure projects, and 9.8 provide technical advice to the commission; 9.9 (3) assist the regional energy infrastructure planning 9.10 groups in analyzing assertions of need for additional 9.11 infrastructure; 9.12 (4) develop and present the reliability status report 9.13 required under subdivision 4 and the state reliability plan 9.14 under section 216B.012; and 9.15 (5) present independent, factual, expert, and technical 9.16 information on infrastructure proposals at public meetings 9.17 hosted by the task force, the environmental quality board, or 9.18 the commission. 9.19 (b) Upon request and subject to resource constraints, the 9.20 administrator shall provide technical assistance regarding 9.21 matters unrelated to applications for infrastructure 9.22 improvements to the task force, the department, or the 9.23 commission. 9.24 Subd. 3. [ADMINISTRATIVE ISSUES.] (a) The commissioner may 9.25 select the administrator whose term shall be concurrent with 9.26 that of the governor. The administrator may be removed only for 9.27 cause. The commissioner shall oversee and direct the work of 9.28 the administrator, annually review the expenses of the 9.29 administrator, and biennially approve the budget of the 9.30 administrator. The administrator may utilize existing 9.31 commission or department staff at the discretion of the chair or 9.32 the commissioner, may hire staff, and may contract for technical 9.33 expertise in performing duties when existing state resources are 9.34 required for other state responsibilities or when special 9.35 expertise is required. The salary of the administrator is 9.36 governed by section 15A.0815, subdivision 2. 10.1 (b) The administrator shall certify its administrative 10.2 costs to the commission on a monthly basis, and shall specify 10.3 those costs that are general in nature and those that were 10.4 incurred on a specific application or with regard to a specific 10.5 utility. 10.6 (c) The legislative energy task force shall make 10.7 assessments for the general administrative costs of the 10.8 administrator pursuant to the assessment authority of the 10.9 legislative electric energy task force under section 216C.051, 10.10 subdivision 6. If sufficient funds are not available under that 10.11 section, the administrator must not incur additional costs and 10.12 the position of administrator must be vacated. In no event 10.13 shall the general fund of the state treasury be responsible for 10.14 any costs of the administrator. Additional amounts for general 10.15 administrative costs may be incurred and recovered above this 10.16 amount if the commissioner and chair of the commission deem the 10.17 additional amounts to be necessary. Costs that are of a general 10.18 nature must be apportioned among all energy utilities in 10.19 proportion to their respective gross operating revenues from 10.20 retail sales of gas or electric service within the state during 10.21 the last calendar year. 10.22 (d) Costs relating to a specific proceeding, analysis, or 10.23 project are not general administrative costs and must be billed 10.24 directly. The commission shall review those costs, and shall 10.25 order payment within 30 days of commission review. The 10.26 department shall render a bill to the utility or utilities, 10.27 either at the conclusion of a particular proceeding, analysis, 10.28 or project, or from time to time during the course of the 10.29 proceeding, analysis, or project. The bill constitutes notice 10.30 of the assessment and a demand for payment. The amount of the 10.31 bills so rendered by the department must be paid by the public 10.32 utility into a special revenue fund in the state treasury within 10.33 30 days from the date of billing and are appropriated to the 10.34 administrator for the purposes provided in this section. 10.35 Appeals may be handled by the commission as provided in section 10.36 216B.62. The commission shall approve or approve as modified a 11.1 rate schedule providing for the automatic adjustment of charges 11.2 to recover amounts paid by utilities under this section. The 11.3 administrator shall provide a detailed accounting of finances to 11.4 the commissioner and to the chairs of the house of 11.5 representatives and senate finance committees with jurisdiction 11.6 over the department's budget. All amounts assessed under this 11.7 section are in addition to amounts appropriated to the 11.8 commission and the department by other law. 11.9 Subd. 4. [RELIABILITY STATUS REPORT.] The commission shall 11.10 require all electric utilities to report to the administrator on 11.11 operating and planning reserves, available transmission 11.12 capacity, outages of major generation units and feeders of 11.13 distribution and transmissions facilities, the adequacy of stock 11.14 and equipment, and any other information necessary to assess the 11.15 current and future reliability of energy service in this state. 11.16 By January 1 of each odd-numbered year beginning in 2003, the 11.17 administrator shall assess and report the status of the 11.18 reliability of electric service in the state to the 11.19 commissioner, with copies to the commission and the legislative 11.20 electric energy task force. 11.21 Sec. 12. [EFFECTIVE DATE.] 11.22 Article 1 is effective the day following final enactment. 11.23 ARTICLE 2 11.24 ESSENTIAL ENERGY INFRASTRUCTURE 11.25 Section 1. Minnesota Statutes 2000, section 116.07, 11.26 subdivision 4a, is amended to read: 11.27 Subd. 4a. [PERMITS.] (a) The pollution control agency may 11.28 issue, continue in effect, or deny permits, under such11.29 conditions asit may prescribe for the prevention of pollution, 11.30 for (1) the emission of air contaminants except for emissions 11.31 from electric generation stations, or for(2) the installation 11.32 or operation of any emission facility, air contaminant treatment 11.33 facility, treatment facility, potential air contaminant storage 11.34 facility, or storage facility, or any part thereof, or for(3) 11.35 the sources or emissions of noise pollution .11.36 The pollution control agency may also issue, continue in12.1 effect or deny permits, under such conditions as it may12.2 prescribe for the prevention of pollution, for, (4) the storage, 12.3 collection, transportation, processing, or disposal of waste, or 12.4 for(5) the installation or operation of any system or facility, 12.5 or any part thereof, related to the storage, collection, 12.6 transportation, processing, or disposal of waste. The 12.7 commissioner, rather than the agency, may issue, continue in 12.8 effect, or deny permits, under conditions the commissioner may 12.9 prescribe for the prevention of pollution, for the emissions of 12.10 air contaminants from electric generation stations. 12.11 The pollution control agency may revoke or modify any permit 12.12 issued under this subdivision and section 116.081 whenever it is 12.13 necessary, in the opinion of the agency, to prevent or abate 12.14 pollution. 12.15 (b) The pollution control agency has the authority for 12.16 approval over the siting, expansion, or operation of a solid 12.17 waste facility with regard to environmental issues. However, 12.18 the agency's issuance of a permit does not release the permittee 12.19 from any liability, penalty, or duty imposed by any applicable 12.20 county ordinances. Nothing in this chapter precludes, or shall 12.21 be construed to preclude, a county from enforcing land use 12.22 controls, regulations, and ordinances existing at the time of 12.23 the permit application and adopted pursuant to sections 366.10 12.24 to 366.181, 394.21 to 394.37, or 462.351 to 462.365, with regard 12.25 to the siting, expansion, or operation of a solid waste facility. 12.26 Sec. 2. Minnesota Statutes 2000, section 116C.52, 12.27 subdivision 10, is amended to read: 12.28 Subd. 10. [UTILITY.] "Utility" shall mean any entity 12.29 engaged or intending to engage in this state in the generation, 12.30 transmission or distribution of electric energy including, but 12.31 not limited to, a private investor owned utility, cooperatively 12.32 owned utility, and a public or municipally owned utility. 12.33 Sec. 3. Minnesota Statutes 2000, section 116C.53, 12.34 subdivision 2, is amended to read: 12.35 Subd. 2. [JURISDICTION.] The board is hereby given the 12.36 authority to provide for site and route selection for large 13.1 electric power facilities. The board shall issue permits for 13.2 large electric power facilities in a timely fashion. When the 13.3 public utilities commission has determined the need for the 13.4 project under section 216B.012 or 216B.243, questions of need, 13.5 including size, type, and timing; alternative system 13.6 configurations; and voltage, are not within the board's siting 13.7 and routing authority and must not be included in the scope of 13.8 environmental review conducted under sections 116C.51 to 116C.69. 13.9 Sec. 4. Minnesota Statutes 2000, section 116C.53, 13.10 subdivision 3, is amended to read: 13.11 Subd. 3. [INTERSTATE ROUTES.] (a) If a route is proposed 13.12 in two or more states, the board shall attempt to reach 13.13 agreement with affected states on the entry and exit points 13.14 prior to authorizing the construction of thedesignating a 13.15 route. The board, in discharge of its duties pursuant to 13.16 sections 116C.51 to 116C.69 may make joint investigations, hold 13.17 joint hearings within or without the state, and issue joint or 13.18 concurrent orders in conjunction or concurrence with any 13.19 official or agency of any state or of the United States. The 13.20 board may negotiate and enter into any agreements or compacts 13.21 with agencies of other states, pursuant to any consent of 13.22 Congress, for cooperative efforts in certifying the 13.23 construction, operation, and maintenance of large electric power 13.24 facilities in accord with the purposes of sections 116C.51 to 13.25 116C.69 and for the enforcement of the respective state laws 13.26 regarding such facilities. 13.27 (b) The board may not issue a route permit for the 13.28 Minnesota portion of an interstate high voltage transmission 13.29 line unless the applicant has received a certificate of need 13.30 from the public utilities commission. 13.31 Sec. 5. Minnesota Statutes 2000, section 116C.57, 13.32 subdivision 1, is amended to read: 13.33 Subdivision 1. [ DESIGNATION OF SITES SUITABLE FOR SPECIFIC13.34 FACILITIES; REPORTSSITE PERMIT.] A utility must apply to the13.35 board in a form and manner prescribed by the board for13.36 designation of a specific site for a specific size and type of14.1 facility. The application shall contain at least two proposed14.2 sites. In the event a utility proposes a site not included in14.3 the board's inventory of study areas, the utility shall specify14.4 the reasons for the proposal and shall make an evaluation of the14.5 proposed site based upon the planning policies, criteria and14.6 standards specified in the inventory. Pursuant to sections14.7 116C.57 to 116C.60, the board shall study and evaluate any site14.8 proposed by a utility and any other site the board deems14.9 necessary which was proposed in a manner consistent with rules14.10 adopted by the board concerning the form, content, and14.11 timeliness of proposals for alternate sites. No site14.12 designation shall be made in violation of the site selection14.13 standards established in section 116C.55. The board shall14.14 indicate the reasons for any refusal and indicate changes in14.15 size or type of facility necessary to allow site designation.14.16 Within a year after the board's acceptance of a utility's14.17 application, the board shall decide in accordance with the14.18 criteria specified in section 116C.55, subdivision 2, the14.19 responsibilities, procedures and considerations specified in14.20 section 116C.57, subdivision 4, and the considerations in14.21 chapter 116D which proposed site is to be designated. The board14.22 may extend for just cause the time limitation for its decision14.23 for a period not to exceed six months. When the board14.24 designates a site, it shall issue a certificate of site14.25 compatibility to the utility with any appropriate conditions.14.26 The board shall publish a notice of its decision in the State14.27 Register within 30 days of site designation.No person may 14.28 construct a large electric power generating plant shall be14.29 constructed except onwithout a site designated bypermit from 14.30 the board or a county. A large electric generating plant may be 14.31 constructed only on either (1) a site approved by the board 14.32 under this section or section 116C.575, or (2) a site designated 14.33 by a county using terms, conditions, procedures, and standards 14.34 no less stringent than those imposed and used by the board. If 14.35 the proposed project is under the jurisdiction of the board, the 14.36 board must incorporate into one proceeding the route selection 15.1 for a high voltage transmission line that is directly associated 15.2 with and necessary to interconnect the large electric generation 15.3 plant to the transmission system and whose need is certified as 15.4 part of the generation plant project by the public utilities 15.5 commission. 15.6 Sec. 6. Minnesota Statutes 2000, section 116C.57, 15.7 subdivision 2, is amended to read: 15.8 Subd. 2. [ DESIGNATION OF ROUTES; PROCEDUREROUTE PERMIT.] 15.9 A utility shall apply to the board in a form and manner15.10 prescribed by the board for a permit for the construction of a15.11 high voltage transmission line. The application shall contain15.12 at least two proposed routes. Pursuant to sections 116C.57 to15.13 116C.60, the board shall study, and evaluate the type, design,15.14 routing, right-of-way preparation and facility construction of15.15 any route proposed in a utility's application and any other15.16 route the board deems necessary which was proposed in a manner15.17 consistent with rules adopted by the board concerning the form,15.18 content, and timeliness of proposals for alternate routes15.19 provided, however, that the board shall identify the alternative15.20 routes prior to the commencement of public hearings thereon15.21 pursuant to section 116C.58. Within one year after the board's15.22 acceptance of a utility's application, the board shall decide in15.23 accordance with the criteria and standards specified in section15.24 116C.55, subdivision 2, and the considerations specified in15.25 section 116C.57, subdivision 4, which proposed route is to be15.26 designated. The board may extend for just cause the time15.27 limitation for its decision for a period not to exceed 90 days.15.28 When the board designates a route, it shall issue a permit for15.29 the construction of a high voltage transmission line specifying15.30 the type, design, routing, right-of-way preparation and facility15.31 construction it deems necessary and with any other appropriate15.32 conditions. The board may order the construction of high15.33 voltage transmission line facilities which are capable of15.34 expansion in transmission capacity through multiple circuiting15.35 or design modifications. The board shall publish a notice of15.36 its decision in the state register within 30 days of issuance of16.1 the permit.No person may construct a high voltage transmission 16.2 line shall be constructed except onwithout a route designated16.3 bypermit from the board , unless it was exempted pursuant to16.4 subdivision 5. A high voltage transmission line may be 16.5 constructed only along a route approved by the board. 16.6 Sec. 7. Minnesota Statutes 2000, section 116C.57, is 16.7 amended by adding a subdivision to read: 16.8 Subd. 2a. [APPLICATION.] (a) A person seeking to construct 16.9 a large electric power generating plant or a high voltage 16.10 transmission line shall apply to the board for a site permit or 16.11 route permit. The application must contain any information 16.12 required by the board and must specify: 16.13 (1) whether the applicant is required to receive a 16.14 certificate of need for the proposed project; 16.15 (2) whether the applicant is required to comply with 16.16 section 216B.019, subdivision 5, and has complied; and 16.17 (3) whether the proposed project was identified, discussed, 16.18 and considered by the relevant regional energy infrastructure 16.19 planning group and the result of that consideration. 16.20 (b) The applicant shall propose at least two sites for a 16.21 large electric power generating plant and two routes for a high 16.22 voltage transmission line. 16.23 (c) The chair of the board shall determine whether an 16.24 application is complete and advise the applicant of any 16.25 deficiencies. An application is not incomplete if information 16.26 not in the application can be obtained from the applicant during 16.27 the first phase of the process and that information is not 16.28 essential for notice and initial public meetings. 16.29 Sec. 8. Minnesota Statutes 2000, section 116C.57, is 16.30 amended by adding a subdivision to read: 16.31 Subd. 2b. [NOTICE OF APPLICATION.] Within 15 days after 16.32 submitting an application to the board, the applicant shall 16.33 publish notice of the application in a legal newspaper of 16.34 general circulation in each county in which the site or route is 16.35 proposed and send a copy of the application by certified mail to 16.36 any regional development commission, county, incorporated 17.1 municipality, and town in which the site or route is proposed. 17.2 Within the same 15 days, the applicant shall also send a notice 17.3 of the submission of the application and description of the 17.4 proposed project to each owner whose property is adjacent to any 17.5 of the proposed sites for the power plant or along any of the 17.6 proposed routes for the transmission line. The notice must 17.7 identify a location where a copy of the application can be 17.8 reviewed. For the purpose of giving mailed notice under this 17.9 subdivision, owners are those shown on the records of the county 17.10 auditor or, in any county where tax statements are mailed by the 17.11 county treasurer, on the records of the county treasurer, but 17.12 other appropriate records may be used for this purpose. The 17.13 failure to give mailed notice to a property owner, or defects in 17.14 the notice, does not invalidate the proceedings, provided a bona 17.15 fide attempt to comply with this subdivision has been made. 17.16 Within the same 15 days, the applicant shall also send the same 17.17 notice of the submission of the application and description of 17.18 the proposed project to those persons who have requested to be 17.19 placed on a list maintained by the board for receiving notice of 17.20 proposed large electric generating power plants and high voltage 17.21 transmission lines. 17.22 Sec. 9. Minnesota Statutes 2000, section 116C.57, is 17.23 amended by adding a subdivision to read: 17.24 Subd. 2c. [ENVIRONMENTAL REVIEW.] The board shall prepare 17.25 an environmental impact statement on each proposed large 17.26 electric generating plant or high voltage transmission line for 17.27 which a complete application has been submitted. For any 17.28 project that has obtained a certificate of need from the public 17.29 utilities commission, the board shall not consider whether or 17.30 not the project is needed. No other state environmental review 17.31 documents are required. The board shall study and evaluate any 17.32 site or route proposed by an applicant and any other site or 17.33 route the board deems necessary that was proposed in a manner 17.34 consistent with rules adopted by the board concerning the form, 17.35 content, and timeliness of proposals for alternate sites or 17.36 routes. 18.1 Sec. 10. Minnesota Statutes 2000, section 116C.57, is 18.2 amended by adding a subdivision to read: 18.3 Subd. 2d. [PUBLIC HEARING.] The board shall hold a public 18.4 hearing on an application for a site permit for a large electric 18.5 power generating plant or a route permit for a high voltage 18.6 transmission line. A hearing held for designating a site or 18.7 route must be conducted by an administrative law judge from the 18.8 office of administrative hearings under the contested case 18.9 procedures of chapter 14. Notice of the hearing must be given 18.10 by the board at least ten days in advance but no earlier than 45 18.11 days prior to the commencement of the hearing. Notice must be 18.12 by publication in a legal newspaper of general circulation in 18.13 the county in which the public hearing is to be held and by 18.14 certified mail to chief executives of the regional development 18.15 commissions, counties, organized towns, townships, and the 18.16 incorporated municipalities in which a site or route is 18.17 proposed. A person may appear at the hearing and offer 18.18 testimony and exhibits without the necessity of intervening as a 18.19 formal party to the proceeding. The administrative law judge 18.20 may allow a person to ask questions of other witnesses. The 18.21 administrative law judge shall hold a portion of the hearing in 18.22 the area where the power plant or transmission line is proposed 18.23 to be located. 18.24 Sec. 11. Minnesota Statutes 2000, section 116C.57, 18.25 subdivision 4, is amended to read: 18.26 Subd. 4. [CONSIDERATIONS IN DESIGNATING SITES AND 18.27 ROUTES.] (a) To facilitate the study, research, evaluation, and 18.28 designation of sites and routes, the board shall be guided by, 18.29 but not limited to, the following responsibilities, procedures, 18.30 and considerations: 18.31 (1) evaluation of research and investigations relating to 18.32 the effects on land, water, and air resources of large electric 18.33 power generating plants and high voltage transmission line 18.34 routes and the effects of water and air discharges and electric 18.35 fields resulting from such facilities on public health and 18.36 welfare, vegetation, animals, materials, and aesthetic values, 19.1 including base line studies, predictive modeling, and monitoring 19.2 of the water and air mass at proposed and operating sites and 19.3 routes, evaluation of new or improved methods for minimizing 19.4 adverse impacts of water and air discharges and other matters 19.5 pertaining to the effects of power plants on the water and air 19.6 environment; 19.7 (2) environmental evaluation of sites and routes proposed 19.8 for future development and expansion and their relationship to 19.9 the land, water, air, and human resources of the state; 19.10 (3) evaluation of the effects of new electric power 19.11 generation and transmission technologies and systems related to 19.12 power plants designed to minimize adverse environmental effects; 19.13 (4) evaluation of the potential for beneficial uses of 19.14 waste energy from proposed large electric power generating 19.15 plants; 19.16 (5) analysis of the direct and indirect economic impact of 19.17 proposed sites and routes including, but not limited to, 19.18 productive agricultural land lost or impaired; 19.19 (6) evaluation of adverse direct and indirect environmental 19.20 effects whichthat cannot be avoided should the proposed site 19.21 and route be accepted; 19.22 (7) evaluation of alternatives to the applicant's proposed 19.23 site or route proposed pursuant to subdivisions 1 and 2; 19.24 (8) evaluation of potential routes whichthat would use or 19.25 parallel existing railroad and highway rights-of-way; 19.26 (9) evaluation of governmental survey lines and other 19.27 natural division lines of agricultural land so as to minimize 19.28 interference with agricultural operations; 19.29 (10) evaluation of the future needs for additional high 19.30 voltage transmission lines in the same general area as any 19.31 proposed route, and the advisability of ordering the 19.32 construction of structures capable of expansion in transmission 19.33 capacity through multiple circuiting or design modifications; 19.34 (11) evaluation of irreversible and irretrievable 19.35 commitments of resources should the proposed site or route be 19.36 approved; and 20.1 (12) wherewhen appropriate, consideration of problems 20.2 raised by other state and federal agencies and local entities. 20.3 (13)(b) If the board's rules are substantially similar to 20.4 existing rules andregulations of a federal agency to which the 20.5 utility in the state is subject, the federal rules and20.6 regulations shallmust be applied by the board. 20.7 (14)(c) No site or route shallmay be designated which20.8 violatesif to do so would violate state agency rules. 20.9 Sec. 12. Minnesota Statutes 2000, section 116C.57, is 20.10 amended by adding a subdivision to read: 20.11 Subd. 7. [TIMING.] The board shall make a final decision 20.12 on an application within 60 days after receipt of the report of 20.13 the administrative law judge. A final decision on the request 20.14 for a site permit or route permit shall be made within one year 20.15 after the chair's determination that an application is 20.16 complete. The time for the final decision may be extended for 20.17 up to 90 days for good cause and if all parties agree. 20.18 Sec. 13. Minnesota Statutes 2000, section 116C.57, is 20.19 amended by adding a subdivision to read: 20.20 Subd. 8. [FINAL DECISION.] (a) A site permit may not be 20.21 issued in violation of the site selection standards and criteria 20.22 established in this section and in rules adopted by the board. 20.23 The board shall indicate the reasons for any refusal and 20.24 indicate changes in size or type of facility necessary to allow 20.25 site designation. When the board designates a site, it shall 20.26 issue a site permit to the applicant with any appropriate 20.27 conditions. The board shall publish a notice of its decision in 20.28 the State Register within 30 days of issuing the site permit. 20.29 (b) A route permit may not be issued in violation of the 20.30 route selection standards and criteria established in this 20.31 section and in rules adopted by the board. When the route is 20.32 designated, the permit issued for the construction of the 20.33 facility must specify the type, design, routing, right-of-way 20.34 preparation, and facility construction deemed necessary and any 20.35 other appropriate conditions. The board may order the 20.36 construction of high voltage transmission line facilities that 21.1 are capable of expansion in transmission capacity through 21.2 multiple circuiting or design modifications. The board shall 21.3 publish a notice of its decision in the State Register within 30 21.4 days of issuing the permit. 21.5 Sec. 14. [116C.575] [ALTERNATIVE REVIEW OF APPLICATIONS.] 21.6 Subdivision 1. [ALTERNATIVE REVIEW.] An applicant who 21.7 seeks a site permit or route permit for one of the projects 21.8 identified in this section may petition the board to be allowed 21.9 to follow the procedures in this section rather than the 21.10 procedures in section 116C.57. The board shall grant the 21.11 petition within 30 days unless the board finds good cause for 21.12 denial. 21.13 Subd. 2. [APPLICABLE PROJECTS.] The requirements and 21.14 procedures in this section may apply to the following projects: 21.15 (1) large electric power generating plants with a capacity 21.16 of less than 80 megawatts; 21.17 (2) large electric power generating plants fueled by 21.18 natural gas; 21.19 (3) projects to retrofit or repower an existing large 21.20 electric power generating plant to one burning primarily natural 21.21 gas or other similar clean fuel; 21.22 (4) any natural gas peaking facility designed for or 21.23 capable of storing on a single site more than 100,000 gallons of 21.24 liquefied natural gas or synthetic gas; 21.25 (5) high voltage transmission lines in excess of 200 21.26 kilovolts less than five miles in length in Minnesota; and 21.27 (6) high voltage transmission lines in excess of 200 21.28 kilovolts if at least 80 percent of the distance of the line in 21.29 Minnesota will be located along existing high voltage 21.30 transmission line right-of-way. 21.31 Subd. 3. [APPLICATION.] The applicant for a site 21.32 certificate or route permit for any of the projects listed in 21.33 subdivision 2 who chooses to follow these procedures shall 21.34 submit information the board may require, but the applicant is 21.35 not required to propose a second site or route for the project. 21.36 The applicant shall identify in the application any other sites 22.1 or routes that were rejected by the applicant and the board may 22.2 identify additional sites or routes to consider during the 22.3 processing of the application. The chair of the board shall 22.4 determine whether an application is complete and advise the 22.5 applicant of any deficiencies. 22.6 Subd. 4. [NOTICE OF APPLICATION.] On submitting an 22.7 application under this section, the applicant shall provide the 22.8 same notice as required by section 116C.57, subdivision 2b. 22.9 Subd. 5. [ENVIRONMENTAL REVIEW.] For the projects 22.10 identified in subdivision 2 and following these procedures, the 22.11 board shall prepare an environmental assessment worksheet. The 22.12 board shall include as part of the environmental assessment 22.13 worksheet alternative sites or routes identified by the board 22.14 and shall address mitigating measures for all of the sites or 22.15 routes considered. The environmental assessment worksheet is 22.16 the only state environmental review document required to be 22.17 prepared on the project. 22.18 Subd. 6. [PUBLIC MEETING.] The board shall hold a public 22.19 meeting in the area where the facility is proposed to be 22.20 located. The board shall give notice of the public meeting in 22.21 the same manner as notice for a public hearing. The board shall 22.22 provide opportunity at the public meeting for any person to 22.23 present comments and to ask questions of the applicant and board 22.24 staff. The board shall also afford interested persons an 22.25 opportunity to submit written comments into the record. 22.26 Subd. 7. [TIMING.] The board shall make a final decision 22.27 on an application within 60 days after completion of the public 22.28 meeting. A final decision on the request for a site permit or 22.29 route permit under this section must be made within six months 22.30 after the chair's determination that an application is 22.31 complete. The time for the final decision may be extended for 22.32 up to 45 days for good cause and if all parties agree. 22.33 Subd. 8. [CONSIDERATIONS.] The considerations in section 22.34 116C.57, subdivision 4, apply to any projects subject to this 22.35 section. 22.36 Subd. 9. [FINAL DECISION.] (a) A site permit may not be 23.1 issued in violation of the site selection standards and criteria 23.2 established in this section and in rules adopted by the board. 23.3 The board shall indicate the reasons for any refusal and 23.4 indicate changes in size or type of facility necessary to allow 23.5 site designation. When the board designates a site, it shall 23.6 issue a site permit to the applicant with any appropriate 23.7 conditions. The board shall publish a notice of its decision in 23.8 the State Register within 30 days of issuance of the site permit. 23.9 (b) A route designation may not be made in violation of the 23.10 route selection standards and criteria established in this 23.11 section and in rules adopted by the board. When the board 23.12 designates a route, it shall issue a permit for the construction 23.13 of a high voltage transmission line specifying the type, design, 23.14 routing, right-of-way preparation, and facility construction it 23.15 deems necessary and specifying any other appropriate 23.16 conditions. The board may order the construction of high 23.17 voltage transmission line facilities that are capable of 23.18 expansion in transmission capacity through multiple circuiting 23.19 or design modifications. The board shall publish a notice of 23.20 its decision in the State Register within 30 days of issuance of 23.21 the permit. 23.22 Sec. 15. [116C.576] [EMERGENCY PERMIT.] 23.23 (a) Any utility whose electric power system requires the 23.24 immediate construction of a large electric power generating 23.25 plant or high voltage transmission line due to a major 23.26 unforeseen event may apply to the board for an emergency permit 23.27 after providing notice in writing to the public utilities 23.28 commission of the major unforeseen event and the need for 23.29 immediate construction. The permit must be issued in a timely 23.30 manner, no later than 195 days after the board's acceptance of 23.31 the application and upon a finding by the board that (1) a 23.32 demonstrable emergency exists, (2) the emergency requires 23.33 immediate construction, and (3) adherence to the procedures and 23.34 time schedules specified in section 116C.57 would jeopardize the 23.35 utility's electric power system or would jeopardize the 23.36 utility's ability to meet the electric needs of its customers in 24.1 an orderly and timely manner. 24.2 (b) A public hearing to determine if an emergency exists 24.3 must be held within 90 days of the application. The board, 24.4 after notice and hearing, shall adopt rules specifying the 24.5 criteria for emergency certification. 24.6 Sec. 16. Minnesota Statutes 2000, section 116C.58, is 24.7 amended to read: 24.8 116C.58 [ PUBLIC HEARINGS; NOTICEANNUAL HEARING.] 24.9 The board shall hold an annual public hearing at a time and 24.10 place prescribed by rule in order to afford interested persons 24.11 an opportunity to be heard regarding its inventory of study24.12 areas and any other aspects of the board's activities and duties24.13 or policies specified in sections 116C.51 to 116C.69. The board24.14 shall hold at least one public hearing in each county where a24.15 site or route is being considered for designation pursuant to24.16 section 116C.57. Notice and agenda of public hearings and24.17 public meetings of the board held in each county shall be given24.18 by the board at least ten days in advance but no earlier than 4524.19 days prior to such hearings or meetings. Notice shall be by24.20 publication in a legal newspaper of general circulation in the24.21 county in which the public hearing or public meeting is to be24.22 held and by certified mailed notice to chief executives of the24.23 regional development commissions, counties, organized towns and24.24 the incorporated municipalities in which a site or route is24.25 proposed. All hearings held for designating a site or route or24.26 for exempting a route shall be conducted by an administrative24.27 law judge from the office of administrative hearings pursuant to24.28 the contested case procedures of chapter 14. Any person may24.29 appear at the hearings and present testimony and exhibits and24.30 may question witnesses without the necessity of intervening as a24.31 formal party to the proceedings.any matters relating to the 24.32 siting of large electric generating power plants and routing of 24.33 high voltage transmission lines. At the meeting, the board 24.34 shall advise the public of the permits issued by the board in 24.35 the past year. The board shall provide at least ten days' 24.36 notice, but no more than 45 days' notice, of the annual meeting 25.1 by mailing notice to those persons who have requested notice and 25.2 by publication in the board's "EQB Monitor." 25.3 Sec. 17. Minnesota Statutes 2000, section 116C.59, 25.4 subdivision 1, is amended to read: 25.5 Subdivision 1. [ADVISORY TASK FORCE.] The board may 25.6 appoint one or more advisory task forces to assist it in 25.7 carrying out its duties. Task forces appointed to evaluate 25.8 sites or routes considered for designation shall be comprised of 25.9 as many persons as may be designated by the board, but at least 25.10 one representative from each of the following: Regional 25.11 development commissions, counties and municipal corporations and 25.12 one town board member from each county in which a site or route 25.13 is proposed to be located. No officer, agent, or employee of a 25.14 utility shall serve on an advisory task force. Reimbursement 25.15 for expenses incurred shall be made pursuant to the rules 25.16 governing state employees. The task forces expire as provided 25.17 in section 15.059, subdivision 6. At the time the task force is 25.18 appointed, the board shall specify the charge to the task 25.19 force. The task force shall expire upon completion of its 25.20 charge, upon designation by the board of alternative sites or 25.21 routes to be included in the environmental impact statement, or 25.22 upon the specific date identified by the board in the charge, 25.23 whichever occurs first. 25.24 Sec. 18. Minnesota Statutes 2000, section 116C.59, 25.25 subdivision 4, is amended to read: 25.26 Subd. 4. [SCIENTIFIC ADVISORY TASK FORCE.] The board may 25.27 appoint one or more advisory task forces composed of technical 25.28 and scientific experts to conduct research and make 25.29 recommendations concerning generic issues such as health and 25.30 safety, underground routes, double circuiting and long-range 25.31 route and site planning. Reimbursement for expenses incurred 25.32 shall be made pursuant to the rules governing reimbursement of 25.33 state employees. The task forces expire as provided in section 25.34 15.059, subdivision 6. The time allowed for completion of a 25.35 specific site or route procedure may not be extended to await 25.36 the outcome of these generic investigations. 26.1 Sec. 19. Minnesota Statutes 2000, section 116C.60, is 26.2 amended to read: 26.3 116C.60 [PUBLIC MEETINGS; TRANSCRIPT OF PROCEEDINGS; 26.4 WRITTEN RECORDS.] 26.5 Meetings of the board, including hearings, shallmust be 26.6 open to the public. Minutes shallmust be kept of board 26.7 meetings and a complete record of public hearings shall be26.8 kept. All books, records, files, and correspondence of the 26.9 board shallmust be available for public inspection at any 26.10 reasonable time. The council shallboard is also besubject to 26.11 chapter 13D. 26.12 Sec. 20. Minnesota Statutes 2000, section 216B.2421, 26.13 subdivision 2, is amended to read: 26.14 Subd. 2. [LARGE ENERGY FACILITY.] "Large energy facility" 26.15 means: 26.16 (1) any electric power generating plant or combination of 26.17 plants at a single site with a combined capacity of 80,000 26.18 kilowatts or more , or any facility of 50,000 kilowatts or more26.19 which requires oil, natural gas, or natural gas liquids as a26.20 fuel and for which an installation permit has not been applied26.21 for by May 19, 1977 pursuant to Minn. Reg. APC 3(a)and 26.22 transmission lines directly associated with the plant that are 26.23 necessary to interconnect the plant to the transmission system; 26.24 (2) any high voltage transmission line with a capacity of 26.25 200100 kilovolts or more and (i) with more than 50ten miles 26.26 of its length in Minnesota, or (ii) any of its length in 26.27 Minnesota and that crosses the state line; or, any high voltage26.28 transmission line with a capacity of 300 kilovolts or more with26.29 more than 25 miles of its length in Minnesota;26.30 (3) any pipeline greater than six inches in diameter and 26.31 having more than 50 miles of its length in Minnesota used for 26.32 the transportation of coal, crude petroleum or petroleum fuels 26.33 or oil or their derivatives; 26.34 (4) any pipeline for transporting natural or synthetic gas 26.35 at pressures in excess of 200 pounds per square inch with more 26.36 than 50 miles of its length in Minnesota; 27.1 (5) any facility designed for or capable of storing on a 27.2 single site more than 100,000 gallons of liquefied natural gas 27.3 or synthetic gas; 27.4 (6) any underground gas storage facility requiring permit 27.5 pursuant to section 103I.681; 27.6 (7) any nuclear fuel processing or nuclear waste storage or 27.7 disposal facility; and 27.8 (8) any facility intended to convert any material into any 27.9 other combustible fuel and having the capacity to process in 27.10 excess of 75 tons of the material per hour. 27.11 Sec. 21. Minnesota Statutes 2000, section 216B.2421, is 27.12 amended by adding a subdivision to read: 27.13 Subd. 4. [MODIFYING EXISTING LARGE ENERGY FACILITY.] 27.14 Refurbishing or upgrading an existing large energy facility 27.15 through the replacement or addition of facility components does 27.16 not require a certificate of need under section 216B.243, unless 27.17 the changes lead to (1) a capacity increase of more than 100 27.18 megawatts, or ten percent of existing capacity, whichever is 27.19 greater, or (2) operation at more than 50 percent higher voltage. 27.20 Sec. 22. Minnesota Statutes 2000, section 216B.243, 27.21 subdivision 2, is amended to read: 27.22 Subd. 2. [CERTIFICATE REQUIRED.] (a) Except as provided in 27.23 paragraph (b), no large energy facility shallmay be sited or 27.24 constructed in Minnesota without the issuance of a certificate 27.25 of need by the commission pursuant to sections 216C.05 to 27.26 216C.30 and this section and consistent with the criteria for 27.27 assessment of need. 27.28 (b) Notwithstanding paragraph (a), a large energy facility 27.29 that is a generation facility of 500 megawatts or less or a 27.30 natural gas peaking facility not owned by a public or municipal 27.31 utility or cooperative electric association and that is not to 27.32 be included in the utility's or association's rate base does not 27.33 need a certificate of need under this section. 27.34 (c) The commission may not issue a certificate of need for 27.35 a generation facility with coal as its primary fuel, unless the 27.36 commission finds that the facility implements the most stringent 28.1 technology and processes technically achievable, to ensure the 28.2 least impact on the state's environment from the facility. 28.3 Sec. 23. Minnesota Statutes 2000, section 216B.243, is 28.4 amended by adding a subdivision to read: 28.5 Subd. 2a. [PUBLIC PURPOSE DESIGNATION.] (a) When filing 28.6 for a certificate of need under this section, an applicant may 28.7 also petition the commission to designate the proposed large 28.8 energy facility a public purpose project. The commission shall 28.9 approve or reject the petition at the same time the commission 28.10 renders its decision under subdivision 5. Notwithstanding 28.11 section 116C.63 or any other law to the contrary, eminent domain 28.12 authority may not be used in constructing a large energy 28.13 facility unless the commission designates the facility a public 28.14 purpose project. The value paid for property in the exercise of 28.15 eminent domain authority may be structured so as to provide for 28.16 the payment of a portion of the revenue derived from the large 28.17 energy facility over a period of years, rather than a lump sum 28.18 payment at the time the property is taken. 28.19 (b) In deciding whether to designate a proposed large 28.20 energy facility as a public purpose project, the commission 28.21 shall consider whether the proposed facility: 28.22 (1) remedies a condition, or set of conditions, that, based 28.23 on the utility's most recent forecast or consistent with the 28.24 transmission expansion plan of a federally approved regional 28.25 transmission organization or regional reliability entity, may 28.26 materially limit the adequacy of electric supply, efficiency of 28.27 electric service, or reliability of electric service to 28.28 Minnesota consumers; 28.29 (2) was identified as a critical need by the relevant 28.30 regional energy infrastructure planning group; 28.31 (3) is consistent with all relevant state goals and 28.32 strategies approved by the legislature under section 216B.017; 28.33 and 28.34 (4) is otherwise in the public interest. 28.35 Sec. 24. Minnesota Statutes 2000, section 216B.243, 28.36 subdivision 3, is amended to read: 29.1 Subd. 3. [SHOWING REQUIRED FOR CONSTRUCTION.] No(a) A 29.2 proposed large energy facility shallmay not be certified for 29.3 construction unless the applicant can show that demand for29.4 electricity cannot be met more cost-effectively through energy29.5 conservation and load-management measures and unless the29.6 applicanthas otherwisejustified its need. 29.7 (b) In assessing need, the commission shall evaluate: 29.8 (1) the accuracy of the long-range energy demand forecasts 29.9 on which the necessity for the facility is based; 29.10 (2) the effect of existing or possible energy conservation29.11 programs under sections 216C.05 to 216C.30 and this section or29.12 other federal or state legislation on long-term energy demand;29.13 (3)the relationship of the proposed facility to overall 29.14 state and regional energy needs, as described in the most recent29.15 state energy policy and conservation report prepared under29.16 section 216C.18including consideration of (i) the most recent 29.17 state energy security blueprint under section 216B.015, (ii) the 29.18 most recent relevant regional energy infrastructure planning 29.19 group report under section 216B.019, and (iii) information from 29.20 federal and regional reliability organizations, regional 29.21 transmission organizations, and other relevant sources; 29.22 (4) promotional activities that may have given rise to the29.23 demand for this facility;29.24 (5) socially beneficial uses of the output(3) 29.25 environmental and socioeconomic benefits of this facility, 29.26 including its uses to protect or enhance environmental quality, 29.27 to increase reliability of energy supply in Minnesota and the 29.28 region, and to induce future development; 29.29 (6) the effects of the facility in inducing future29.30 development;29.31 (7)(4) possible alternatives for satisfying the energy 29.32 demand or transmission needs including but not limited to 29.33 potential for increased efficiency and upgrading of existing 29.34 energy generation and transmission facilities, load management 29.35 programs, and distributed generation; 29.36 (8)(5) the policies, rules, and regulations of other state 30.1 and federal agencies and local governments; and30.2 (9) any(6) feasible combination ofenergy conservation 30.3 improvements, required under section 216B.241, sections 216C.05 30.4 to 216C.30, or other available conservation programs that can (i) 30.5 reasonably replace a significant part or all of the energy to be 30.6 provided by the proposed facility, and (ii) compete with it 30.7 economically and in terms of reliability; and 30.8 (7) whether the proposed large energy facility was 30.9 recommended for construction by the relevant regional energy 30.10 infrastructure planning group. 30.11 Sec. 25. Minnesota Statutes 2000, section 216B.243, 30.12 subdivision 4, is amended to read: 30.13 Subd. 4. [APPLICATION FOR CERTIFICATE; HEARING.] Any 30.14 person proposing to construct a large energy facility shall 30.15 apply for a certificate of need prior to construction of the 30.16 facility. The application shallmust be on forms and in a 30.17 manner established by the commission. In reviewing each 30.18 application the commission shall hold at least one public 30.19 hearing pursuant to chapter 14. The public hearing shallmust 30.20 be held at a location and hour reasonably calculated to be 30.21 convenient for the public. An objective of the public 30.22 hearing shallmust be to obtain public opinion on the necessity 30.23 of granting a certificate of need. The commission shall 30.24 designate a commission employee whose duty shall be to 30.25 facilitate citizen participation in the hearing process. If the 30.26 commission and the environmental quality board determine that a 30.27 joint hearing on siting and need under this subdivision and 30.28 section 116C.57, subdivision 2d, is feasible, more efficient, 30.29 and may further the public interest, a joint hearing under those 30.30 subdivisions may be held. 30.31 Sec. 26. [INSTRUCTION TO REVISOR.] 30.32 The revisor of statutes shall renumber Minnesota Statutes, 30.33 section 116C.57, subdivision 6, as section 116C.57, subdivision 30.34 9. 30.35 Sec. 27. [REPEALER.] 30.36 Minnesota Statutes 2000, sections 116C.55; 116C.57, 31.1 subdivisions 3, 5, and 5a; and 116C.67, are repealed. 31.2 Sec. 28. [EFFECTIVE DATE.] 31.3 This article is effective the day following final enactment. 31.4 ARTICLE 3 31.5 REGULATORY FLEXIBILITY 31.6 Section 1. Minnesota Statutes 2000, section 216B.16, 31.7 subdivision 7, is amended to read: 31.8 Subd. 7. [ENERGY COST ADJUSTMENT.] (a) Notwithstanding any 31.9 other provision of this chapter, the commission may permit a 31.10 public utility to file rate schedules containing provisions for 31.11 the automatic adjustment of charges for public utility service 31.12 in direct relation to changes in: (1) federally regulated 31.13 wholesale rates for energy delivered through interstate 31.14 facilities; (2) direct costs for natural gas delivered; or (3) 31.15 costs for fuel used in generation of electricity or the 31.16 manufacture of gas. 31.17 (b) In reviewing utility fuel purchases under this or any 31.18 other provision, the commission shall allow and encourage a 31.19 utility to have a combination of measures to manage price 31.20 volatility and risk, including but not limited to having an 31.21 appropriate share of the utility's supply come from long-term 31.22 and medium-term contracts, in order to minimize consumer 31.23 exposure to fuel price volatility. 31.24 Sec. 2. [216B.169] [RENEWABLE AND HIGH EFFICIENCY ENERGY 31.25 RATE OPTIONS.] 31.26 (a) Each public utility, cooperative association, and 31.27 municipal utility shall offer its customers, and shall advertise 31.28 the offer at least annually, one or more options that allow a 31.29 customer to determine that a certain amount of the electricity 31.30 generated or purchased on behalf of the customer is (1) 31.31 renewable energy as defined in section 216B.2422, subdivision 1, 31.32 paragraph (c), or (2) high-efficiency, low-emissions, 31.33 distributed generation such as fuel cells and microturbines 31.34 fueled by a renewable fuel. 31.35 (b) Each public utility shall file an implementation plan 31.36 within 90 days of the effective date of this section to 32.1 implement paragraph (a). 32.2 (c) Rates charged to customers must be calculated using the 32.3 utility's or association's cost of acquiring the energy for the 32.4 customer and must be (1) the difference between the cost of 32.5 generating or purchasing the renewable energy and the cost of 32.6 generating or purchasing the same amount of nonrenewable energy; 32.7 and (2) distributed on a per kilowatt-hour basis among all 32.8 customers who choose to participate in the program. 32.9 Implementation of these rate options may reflect a reasonable 32.10 amount of lead time necessary to arrange acquisition of the 32.11 energy. 32.12 (d) If a utility is not able to arrange an adequate supply 32.13 of renewable or high-efficiency energy to meet its customers' 32.14 demand under this section, the utility must file a report with 32.15 the commission detailing its efforts and reasons for its failure. 32.16 (e) The commission, by order, may establish a program for 32.17 tradeable credits for renewable energy under this section. 32.18 Sec. 3. [216B.2411] [CONSERVATION INVESTMENT PROGRAM.] 32.19 Subdivision 1. [DEFINITIONS.] For purposes of this section 32.20 and section 216B.16, subdivision 6b, the terms defined in this 32.21 subdivision have the meanings given them. 32.22 (a) "Commission" means the public utilities commission. 32.23 (b) "Commissioner" means the commissioner of commerce. 32.24 (c) "Customer facility" means all buildings, structures, 32.25 equipment, and installations at a single site. 32.26 (d) "Department" means the department of commerce. 32.27 (e) "Energy conservation improvement" means the purchase or 32.28 installation of a device, method, material, or project: 32.29 (1) that reduces consumption of or increases efficiency in 32.30 the use of electricity or natural gas, including but not limited 32.31 to insulation and ventilation, storm or thermal doors or 32.32 windows, caulking and weatherstripping, furnace efficiency 32.33 modifications, thermostat or lighting controls, awnings, or 32.34 systems to turn off or vary the delivery of energy; 32.35 (2) that either (i) creates, converts, or actively uses 32.36 energy from renewable sources such as solar, wind, and biomass, 33.1 or (ii) recovers energy for reuse, from air or water or other 33.2 similar material, provided that the device or method conforms 33.3 with national or state performance and quality standards 33.4 whenever applicable; 33.5 (3) that seeks to provide energy savings through 33.6 reclamation or recycling and that is used as part of the 33.7 infrastructure of an electric generation, transmission, or 33.8 distribution system within the state or a natural gas 33.9 distribution system within the state; 33.10 (4) that provides research or development of new means of 33.11 increasing energy efficiency or conserving energy or research or 33.12 development of improvement of existing means of increasing 33.13 energy efficiency or conserving energy; or 33.14 (5) that either (i) is a renewable energy facility, such as 33.15 a facility utilizing agricultural wastes as biomass fuel, or a 33.16 methane digester facility associated with livestock feedlots for 33.17 the production of energy, the grants for which should be 33.18 coordinated with loans under the shared savings loan program 33.19 established in section 17.115 to the extent feasible; (ii) 33.20 increases a customer's ability to control the amount and 33.21 scheduling of energy purchased from a utility, such as through 33.22 the installation of a distributed generation facility as 33.23 described in section 216B.169; or (iii) allows the utility or 33.24 the customer to manage customer load if doing so reduces the 33.25 demand for or increases the efficiency of electric services. 33.26 (f) "Investments and expenses of a public utility" includes 33.27 the investments and expenses incurred by a public utility in 33.28 connection with an energy conservation improvement, including 33.29 but not limited to: 33.30 (1) the differential in interest cost between the market 33.31 rate and the rate charged on a no-interest or below-market 33.32 interest loan made by a public utility to a customer for the 33.33 purchase or installation of an energy conservation improvement; 33.34 and 33.35 (2) the difference between the utility's cost of purchase 33.36 or installation of energy conservation improvements and any 34.1 price charged by a public utility to a customer for those 34.2 improvements. 34.3 (g) "Large electric customer facility" means a customer 34.4 facility that imposes a peak electrical demand on an electric 34.5 utility's system of not less than 10,000 kilowatts, measured in 34.6 the same way as the utility that serves the customer facility 34.7 measures electrical demand for billing purposes, and for which 34.8 electric services are provided at retail on a single bill by a 34.9 utility operating in the state. 34.10 (h) "Utility" means a public utility, municipal utility, 34.11 electric cooperative association, or any combination of these 34.12 authorized under Minnesota law. 34.13 Subd. 2. [INVESTMENT, EXPENDITURE, AND CONTRIBUTION; 34.14 PUBLIC UTILITY.] (a) Each public utility shall spend and invest 34.15 for energy conservation improvements under this subdivision the 34.16 following amounts: 34.17 (1) for a public utility that furnishes gas service, 0.5 34.18 percent of its annual average gross operating revenues over the 34.19 previous five years from service provided in the state; 34.20 (2) for a public utility that furnishes electric service, 34.21 1.5 percent of its annual average gross operating revenues over 34.22 the previous five years from service provided in the state; and 34.23 (3) for a public utility that furnishes electric service 34.24 and that operates a nuclear-powered electric generating plant 34.25 within the state, 2.0 percent of its annual average gross 34.26 operating revenues over the previous five years from service 34.27 provided in the state. 34.28 (b) Load management may only be used to meet the 34.29 requirements for energy conservation improvements under this 34.30 section if it results in a demonstrable reduction in consumption 34.31 of energy. However, up to five percent of the total amount 34.32 required to be spent under this section may be spent on 34.33 conservation improvements described in subdivision 1, paragraph 34.34 (e), clause (5). Each public utility subject to this 34.35 subdivision may spend and invest annually up to 15 percent of 34.36 the total amount required to be spent and invested on energy 35.1 conservation improvements under this section by the utility on 35.2 research and development projects that meet the definition of 35.3 energy conservation improvement in subdivision 1 and that are 35.4 funded directly by the public utility. 35.5 Subd. 3. [CONSERVATION IMPROVEMENT BY COOPERATIVE 35.6 ASSOCIATION OR MUNICIPALITY.] (a) This subdivision applies to: 35.7 (1) a cooperative electric association that generates and 35.8 transmits electricity to associations that provide electricity 35.9 at retail including a cooperative electric association not 35.10 located in this state that serves associations or others in the 35.11 state; 35.12 (2) a municipality that provides electric service to retail 35.13 customers; and 35.14 (3) a municipality with gross operating revenues in excess 35.15 of $5,000,000 from sales of natural gas to retail customers. 35.16 (b) Each cooperative electric association and municipality 35.17 subject to this subdivision shall spend and invest for energy 35.18 conservation improvements under this subdivision the following 35.19 amounts: 35.20 (1) for a municipality, 0.5 percent of its annual average 35.21 gross operating revenues over the previous five years from the 35.22 sale of gas and 1.0 percent of its annual average gross 35.23 operating revenues over the previous five years from the sale of 35.24 electricity; and 35.25 (2) for a cooperative electric association, 1.5 percent of 35.26 its annual average gross operating revenues over the previous 35.27 five years from service provided in the state. 35.28 (c) Each municipality and cooperative association subject 35.29 to this subdivision shall identify and implement energy 35.30 conservation improvement spending and investments that are 35.31 appropriate for the municipality or association. Municipal 35.32 utilities and electric cooperative associations may agree to 35.33 form associations or organizations to aggregate their 35.34 conservation spending obligations and to jointly provide energy 35.35 conservation services to the customers of the municipal 35.36 utilities or associations, and shall notify the commissioner in 36.1 writing of the formation of such an association or organization. 36.2 (d) Each municipality and cooperative electric association 36.3 subject to this subdivision may spend and invest annually up to 36.4 15 percent of the total amount required to be spent and invested 36.5 on energy conservation improvements under this subdivision on 36.6 research and development projects that meet the definition of 36.7 energy conservation improvement in subdivision 1 and that are 36.8 funded directly by the municipality or cooperative electric 36.9 association. 36.10 (e) Load management may only be used to meet the 36.11 requirements of this subdivision if it reduces the demand for or 36.12 increases the efficiency of electric services. 36.13 (f) Up to five percent of the total amount required to be 36.14 spent under this section may be spent on conservation 36.15 improvements described in subdivision 1, paragraph (e), clause 36.16 (5). 36.17 (g) A generation and transmission cooperative electric 36.18 association may include as spending and investment required 36.19 under this subdivision conservation improvement spending and 36.20 investment by cooperative electric associations that provide 36.21 electric service at retail to consumers and that are served by 36.22 the generation and transmission association. 36.23 Subd. 4. [PROGRAMS.] (a) The commissioner may by rule as 36.24 resources allow, or by order, establish standards and criteria 36.25 for the provision of energy conservation improvements, including 36.26 standard programs, to efficiently and effectively provide energy 36.27 conservation services to each utility's energy consumers on a 36.28 nondiscriminatory basis and cost-effective manner and to provide 36.29 certainty to utilities and associations as to what constitutes 36.30 an acceptable energy conservation improvement under this 36.31 section. The list of standard programs may include rebates for 36.32 high-efficiency appliances, rebates or subsidies for 36.33 high-efficiency lamps, small business energy audits, and 36.34 building recommissioning. A utility may adhere to this list of 36.35 programs or may offer other conservation programs not on the 36.36 list. 37.1 (b) Each public utility shall ensure that a portion of the 37.2 money spent on residential conservation improvement programs is 37.3 devoted to programs that directly address the needs of renters 37.4 and low-income persons unless an insufficient number of 37.5 appropriate programs is available. 37.6 (c) A utility, a political subdivision, or a nonprofit or 37.7 community organization that has suggested an energy conservation 37.8 improvement program to a public utility, the attorney general 37.9 acting on behalf of consumers and small business interests, or a 37.10 utility customer that has suggested a program and is not 37.11 represented by the attorney general under section 8.33 may 37.12 petition the commission to modify or discontinue a utility 37.13 energy conservation improvement program, and the commission may 37.14 do so if it determines that the program is not sufficiently cost 37.15 effective, does not adequately address the residential 37.16 conservation improvement needs of low-income persons, has a 37.17 long-range negative effect on one or more classes of customers, 37.18 or is otherwise not in the public interest. The person 37.19 petitioning for commission review has the burden of proof. The 37.20 commission shall reject a petition that, on its face, fails to 37.21 make a reasonable argument that a program is not in the public 37.22 interest. 37.23 Subd. 5. [ENERGY SAVINGS GOALS.] (a) By August 1, 2001, 37.24 and every three years thereafter, the commissioner shall develop 37.25 energy savings goals: 37.26 (1) in kilowatts and kilowatt-hours that each public 37.27 utility providing retail electric service in this state can 37.28 reasonably be expected to achieve at the level of energy 37.29 conservation improvement expenditures required under this 37.30 section; and 37.31 (2) in cubic feet of natural gas that each public utility 37.32 providing retail natural gas service in this state can 37.33 reasonably be expected to achieve at the level of conservation 37.34 improvement expenditures required under this section. 37.35 (b) In consultation with the commissioner, municipal 37.36 utilities and cooperative electric associations shall develop 38.1 and submit energy savings goals to the commissioner by August 1, 38.2 2001, and every three years thereafter. 38.3 (c) Municipal utilities and electric cooperative 38.4 associations that agree to aggregate their energy conservation 38.5 obligations and resources by forming associations or 38.6 organizations to provide energy conservation services to their 38.7 customers may develop goals for the association or organization, 38.8 in lieu of goals for individual members. 38.9 Subd. 6. [OVERVIEW; REVIEW AND AUDIT; PUBLIC 38.10 UTILITIES.] (a) By January 1, 2002, and every three years 38.11 thereafter, each public utility shall provide the commissioner 38.12 with a prospective overview of the utility's planned 38.13 conservation activities and the anticipated energy savings on a 38.14 triennial basis. This overview must include a description of 38.15 the types of activities, the consumer sectors targeted by each 38.16 activity, and the anticipated energy savings and costs of each 38.17 activity. This overview must also indicate, for each type of 38.18 activity, how much additional cost-effective conservation is 38.19 likely to be achieved in subsequent years. A public utility may 38.20 request the commissioner to approve or reject the utility's plan 38.21 prior to implementing the plan. The commissioner may do so if 38.22 resources permit. 38.23 (b) By April 1, 2005, and every three years thereafter, 38.24 each public utility shall provide a report to the commissioner, 38.25 acting on behalf of the commission, summarizing the utility's 38.26 conservation activities and energy savings resulting from those 38.27 activities under this section. The public utility shall include 38.28 in the report the results of an independent audit performed by 38.29 the department or an auditor with experience in the provision of 38.30 energy conservation and energy efficiency services approved by 38.31 the commissioner and chosen by the utility. The audit must 38.32 specify the actual energy savings or increased efficiency in the 38.33 use of energy within the service territory of the utility that 38.34 is the result of the spending and investments. Annually 38.35 beginning by April 1, 2003, except for those years a full audit 38.36 is due, each utility shall submit a report to the commissioner 39.1 detailing the utility's energy conservation activities for the 39.2 previous year and provide information regarding the cost 39.3 effectiveness of those activities. 39.4 (c) The audit provided under paragraph (b) shall evaluate 39.5 the cost effectiveness of the utility's conservation programs. 39.6 In making this evaluation, the audit shall consider whether the 39.7 utility's programs: 39.8 (1) fairly address each of the utility's consumer classes 39.9 and market sectors; 39.10 (2) use accurate and complete data in calculating costs and 39.11 energy savings; 39.12 (3) identify and target investments and improvements that 39.13 have a high potential for saving energy; 39.14 (4) indicate an adequate commitment to implementing highly 39.15 cost-effective conservation programs; and 39.16 (5) comply with the provisions of this section and 39.17 associated rules and orders. 39.18 An audit must give a negative evaluation if it finds the 39.19 utility's overall energy conservation program has not been cost 39.20 effective or has failed to satisfy any of the criteria. Up to 39.21 five percent of a utility's conservation spending obligation 39.22 under this section may be used for program pre-evaluation, 39.23 research and testing, monitoring, and program audit and 39.24 evaluation. 39.25 (d) Following each submittal of an annual report or a 39.26 triennial audit, the commissioner shall issue a report to the 39.27 commission as to whether: 39.28 (1) the utility's overall conservation program is cost 39.29 effective and is in compliance with this section and all 39.30 applicable rules or orders; and 39.31 (2) the utility has been successful in achieving the energy 39.32 savings goals for that utility under subdivision 5. 39.33 (e) Following two or more negative evaluations under 39.34 paragraph (b), the commission may determine that a utility is 39.35 not implementing adequate energy conservation programs. In that 39.36 event, the commission may order the utility to pay into the 40.1 energy and conservation account under subdivision 10, up to 50 40.2 percent of the utility's or association's conservation spending 40.3 obligation under this section. The commissioner shall select a 40.4 third party other than the utility by competitive bid to provide 40.5 conservation improvements in the utility's service territory. 40.6 Subd. 7. [OVERVIEW AND PROGRAM EVALUATION; MUNICIPAL AND 40.7 COOPERATIVE UTILITIES.] (a) By January 1, 2002, and every three 40.8 years thereafter, each municipal utility and electric 40.9 cooperative association shall provide the commissioner with a 40.10 prospective overview of the utility's or association's planned 40.11 conservation activities and the anticipated energy savings on a 40.12 triennial basis. This overview must include a description of 40.13 the types of activities, the consumer sectors targeted by each, 40.14 and the anticipated energy savings and costs of each activity. 40.15 This overview must also indicate, for each type of activity, how 40.16 much additional cost-effective conservation is likely to be 40.17 achieved in subsequent years. 40.18 (b) By February 2, 2002, and every three years thereafter, 40.19 each municipal utility or cooperative association shall provide 40.20 an evaluation to the commission summarizing the utility's or 40.21 association's conservation activities and energy savings 40.22 resulting from those activities under this section. In 40.23 consultation with the commissioner, the municipal utility or 40.24 cooperative association shall evaluate its energy and capacity 40.25 conservation programs, develop plans for future programs, and 40.26 report its findings to the commission. The evaluation must 40.27 develop program and performance goals that recognize customer 40.28 class, utility service area demographics, cost of program 40.29 delivery, regional economic indicators, and utility load shape. 40.30 The program evaluation must address: 40.31 (1) whether the utility or association has implemented or 40.32 is implementing cost-effective energy conservation programs and 40.33 specify the energy and capacity savings within the service 40.34 territory or association that is the result of conservation 40.35 improvement programs, using a list of baseline energy and 40.36 capacity savings assumptions developed in consultation with the 41.1 department of commerce; 41.2 (2) the availability of basic conservation services and 41.3 programs to customers; 41.4 (3) methodologies that best quantify energy savings, cost 41.5 effectiveness, and the potential for cost-effective conservation 41.6 improvements; 41.7 (4) the value of local administration of conservation 41.8 programs in meeting local and statewide needs; 41.9 (5) the effect on customer bills; 41.10 (6) the role of capacity conservation in meeting utility 41.11 planning needs and state energy goals; 41.12 (7) the ability of energy conservation programs to avoid 41.13 the need for construction of generation facilities and 41.14 transmission lines; 41.15 (8) whether the utility's or association's programs address 41.16 all of the following consumer market sectors: farm, 41.17 residential, commercial, and industrial; and 41.18 (9) whether the utility's or association's programs use 41.19 accurate and auditable data in calculating costs and energy 41.20 savings. 41.21 (c) Municipal utilities and electric cooperative 41.22 associations that aggregate their energy conservation 41.23 obligations and resources by forming associations or 41.24 organizations to provide energy conservation services to their 41.25 customers may submit overviews, program evaluations, and annual 41.26 reports jointly. 41.27 Subd. 8. [ADDITIONAL CONSERVATION SPENDING.] (a) Nothing 41.28 in this section prohibits any utility from spending or investing 41.29 more for energy conservation improvements than is required in 41.30 this section. 41.31 (b) The commission may require a public utility to invest 41.32 or spend more than is required under this section if the 41.33 commission finds that additional investments would be cost 41.34 effective, and the utility's most recent forecast projects a 41.35 significant supply deficit to meet demand and energy 41.36 requirements. If the commission orders the utility to make 42.1 additional conservation investments under this section, the 42.2 commission shall provide for financial incentives for these 42.3 investments under section 216B.16. 42.4 Subd. 9. [LARGE CUSTOMER OPT-OUT.] (a) The owner of a 42.5 large electric customer facility may petition the commissioner 42.6 to exempt both electric and gas utilities serving the large 42.7 energy customer facility from the investment and expenditure 42.8 requirements of subdivision 2 with respect to retail revenues 42.9 attributable to the facility. The petition must contain an 42.10 audit by a consultant registered with the department and 42.11 selected by the customer, certifying that the customer has 42.12 implemented all energy conservation improvements with a ten-year 42.13 simple payback or less. Within five business days of receipt of 42.14 a petition that contains this audit, the commissioner shall 42.15 either: 42.16 (1) grant the petition exempting both electric and gas 42.17 utilities serving the large energy customer facility from the 42.18 investment and expenditure requirements of this section with 42.19 respect to all of the retail revenues attributable to the 42.20 facility; or 42.21 (2) order a confirming audit of the customer. 42.22 (b) The decision to grant the petition or order a 42.23 confirming audit is entirely within the discretion of the 42.24 commissioner. The cost of the initial audit must be borne by 42.25 the customer. 42.26 (c) If the commissioner orders a confirming audit, the 42.27 commissioner shall select a contractor from the list maintained 42.28 by the department and notify the customer. 42.29 (d) If the confirming audit supports the initial audit: 42.30 (1) the commissioner shall issue an order granting the 42.31 petition within five business days; and 42.32 (2) the cost of the confirming audit must be borne by the 42.33 electric and gas utilities serving the customer, in relative 42.34 proportion to the total retail revenues attributable to the 42.35 customer, and deducted from the utility's conservation spending 42.36 obligation under this section. 43.1 (e) If the confirming audit does not support the initial 43.2 audit: 43.3 (1) the cost of the confirming audit must be borne by the 43.4 customer; and 43.5 (2) the commissioner may suspend the consultant that 43.6 conducted the initial audit from the list maintained by the 43.7 department. 43.8 (f) The commissioner shall create, maintain, and publish on 43.9 the department's Web site a list of contractors available to 43.10 conduct audits under this subdivision. The commissioner may 43.11 spend no more than $20,000 per biennium under this subdivision. 43.12 (g) If a petition is filed on or before October 1 of any 43.13 year, the order of the commissioner to exempt revenues 43.14 attributable to the facility can be effective no earlier than 43.15 January 1 of the following year. The commissioner may, after 43.16 investigation, recommend that any exemption granted under this 43.17 paragraph be rescinded upon a determination that additional 43.18 energy conservation improvements with a simple payback of ten 43.19 years or less are available at the large electric customer 43.20 facility. For the purposes of investigations by the 43.21 commissioner under this paragraph, the owner of any large 43.22 electric customer facility shall, upon request, provide the 43.23 commissioner with updated information comparable to that 43.24 originally supplied in or with the owner's original petition 43.25 under paragraph (a). 43.26 (h) For purposes of this section, "gross operating 43.27 revenues" do not include revenues from large electric customer 43.28 facilities exempted by the commissioner under this subdivision. 43.29 A public utility may not spend for or invest in energy 43.30 conservation improvements that directly benefit a large electric 43.31 customer facility for which the commissioner has issued an 43.32 exemption pursuant to this subdivision. 43.33 Subd. 10. [ENERGY AND CONSERVATION ACCOUNT.] (a) Money in 43.34 the account is appropriated to the department for programs 43.35 designed to meet the energy conservation needs of low-income 43.36 persons and to make energy conservation improvements in areas 44.1 not adequately served including research and development 44.2 projects included in the definition of energy conservation 44.3 improvement in subdivision 1. Interest on money in the account 44.4 accrues to the account. 44.5 (b) Using information collected under section 216C.02, 44.6 subdivision 1, paragraph (b), the commissioner must, to the 44.7 extent possible, allocate enough money to programs for 44.8 low-income persons to assure that their needs are being 44.9 adequately addressed. The commissioner must request the 44.10 commissioner of finance to transfer money from the account to 44.11 the commissioner of economic security for an energy conservation 44.12 program for low-income persons. In establishing programs under 44.13 this paragraph, the commissioner must consult political 44.14 subdivisions and nonprofit and community organizations, 44.15 especially organizations engaged in providing energy and 44.16 weatherization assistance to low-income persons. At least one 44.17 program must address the need for energy conservation 44.18 improvements in areas in which a high percentage of residents 44.19 use fuel oil or propane to fuel their source of home heating. 44.20 (c) The commissioner may contract with a political 44.21 subdivision, a nonprofit or community organization, a public 44.22 utility, a municipality, or a cooperative electric association 44.23 to implement its programs under this section. The commissioner 44.24 may provide grants to any person to conduct research and 44.25 development projects in accordance with this section. 44.26 Subd. 11. [RECOVERY OF EXPENSES.] (a) The commission shall 44.27 allow a public utility to recover expenses resulting from a 44.28 conservation improvement program consistent with the 44.29 requirements of this section and contributions to the energy and 44.30 conservation account, unless the recovery would be inconsistent 44.31 with a financial incentive proposal approved by the commission. 44.32 In addition, a utility may file annually, or the public 44.33 utilities commission may require the utility to file, and the 44.34 commission may approve, rate schedules containing provisions for 44.35 the automatic adjustment of charges for utility service in 44.36 direct relation to changes in the expenses of the utility for 45.1 real and personal property taxes, fees, and permits, the amounts 45.2 of which the utility cannot control. 45.3 (b) A public utility is eligible to file for adjustment for 45.4 real and personal property taxes, fees, and permits under this 45.5 subdivision only if, in the year previous to the year in which 45.6 it files for adjustment, it has spent or invested at least 2.25 45.7 percent of its gross revenues from provision of electric 45.8 service, excluding gross operating revenues from electric 45.9 service provided in the state to large electric customer 45.10 facilities for which the commissioner has issued an exemption 45.11 under subdivision 9, and 0.75 percent of its gross revenues from 45.12 provision of gas service, excluding gross operating revenues 45.13 from gas services provided in the state to large electric 45.14 customer facilities for which the commissioner has issued an 45.15 exemption under subdivision 9, for that year for energy 45.16 conservation improvements under this section. 45.17 Subd. 12. [OWNERSHIP OF ENERGY CONSERVATION 45.18 IMPROVEMENT.] An energy conservation improvement made to or 45.19 installed in a building in accordance with this section, except 45.20 systems owned by the utility and designed to turn off, limit, or 45.21 vary the delivery of energy, are the exclusive property of the 45.22 owner of the building except to the extent that the improvement 45.23 is subjected to a security interest in favor of the utility in 45.24 case of a loan to the building owner. The utility has no 45.25 liability for loss, damage, or injury caused directly or 45.26 indirectly by an energy conservation improvement except for 45.27 negligence by the utility in purchase, installation, or 45.28 modification of the product. 45.29 Subd. 13. [FEDERAL LAW PROHIBITIONS.] If investments by 45.30 public utilities in energy conservation improvements are in any 45.31 manner prohibited or restricted by federal law and there is a 45.32 provision under which the prohibition or restriction may be 45.33 waived, then the commission, the governor, or any other 45.34 necessary state agency or officer shall take all necessary and 45.35 appropriate steps to secure a waiver with respect to those 45.36 public utility investments in energy conservation improvements 46.1 included in this section. 46.2 Subd. 14. [EFFICIENT LIGHTING PROGRAM.] (a) Each public 46.3 utility, cooperative electric association, and municipal utility 46.4 that provides electric service to retail customers shall include 46.5 as part of its conservation improvement activities a program to 46.6 strongly encourage the use of fluorescent and high intensity 46.7 discharge lamps. The program must include at least a public 46.8 information campaign to encourage use of the lamps and proper 46.9 management of spent lamps by all customer classifications. 46.10 (b) A public utility that provides electric service at 46.11 retail to 200,000 or more customers shall establish, either 46.12 directly or through contracts with other persons, including lamp 46.13 manufacturers, distributors, wholesalers, and retailers and 46.14 local government units, a system to collect for delivery to a 46.15 reclamation or recycling facility spent fluorescent and 46.16 high-intensity discharge lamps from households and from small 46.17 businesses as defined in section 645.445 that generate an 46.18 average of fewer than ten spent lamps per year. 46.19 (c) A collection system must include establishing 46.20 reasonably convenient locations for collecting spent lamps from 46.21 households and financial incentives sufficient to encourage 46.22 spent lamp generators to take the lamps to the collection 46.23 locations. Financial incentives may include coupons for 46.24 purchase of new fluorescent or high-intensity discharge lamps, a 46.25 cash-back system, or any other financial incentive or group of 46.26 incentives designed to collect the maximum number of spent lamps 46.27 from households and small businesses that is reasonably feasible. 46.28 (d) A public utility that provides electric service at 46.29 retail to fewer than 200,000 customers, a cooperative electric 46.30 association, or a municipal utility that provides electric 46.31 service at retail to customers may establish a collection system 46.32 under paragraphs (b) and (c) as part of conservation improvement 46.33 activities required under this section. 46.34 (e) The commissioner of the pollution control agency may 46.35 not, unless clearly required by federal law, require a public 46.36 utility, cooperative electric association, or municipality that 47.1 establishes a household fluorescent and high-intensity discharge 47.2 lamp collection system under this section to manage the lamps as 47.3 hazardous waste as long as the lamps are managed to avoid 47.4 breakage and are delivered to a recycling or reclamation 47.5 facility that removes mercury and other toxic materials 47.6 contained in the lamps prior to placement of the lamps in solid 47.7 waste. 47.8 (f) If a utility contracts with a local government unit to 47.9 provide a collection system under this subdivision, the contract 47.10 must provide for payment to the local government unit of all the 47.11 unit's incremental costs of collecting and managing spent lamps. 47.12 (g) All the costs incurred by a public utility, cooperative 47.13 electric association, or municipal utility for promotion and 47.14 collection of fluorescent and high-intensity discharge lamps 47.15 under this subdivision constitute conservation improvement 47.16 spending under this section. 47.17 Sec. 4. Minnesota Statutes 2000, section 216B.2422, 47.18 subdivision 2, is amended to read: 47.19 Subd. 2. [RESOURCE PLAN FILING AND APPROVAL.] A utility 47.20 shall file a resource plan with the commission periodically in 47.21 accordance with rules adopted by the commission. The commission47.22 shall approve, reject, or modify the plan of a public utility,47.23 as defined in section 216B.02, subdivision 4, consistent with47.24 the public interest.In the resource plan proceedings of 47.25 all otherutilities, the commission'sutility may request the 47.26 commission to approve or reject the resource plan, and the 47.27 commission may do so if the resources of both the commission and 47.28 the department permit. Otherwise, the filing of the plan is 47.29 informational only. If the utility requests the commissioner to 47.30 waive the need for a certificate of need under subdivision 6 or 47.31 to approve a bidding schedule under subdivision 5, the 47.32 commission's order is binding. Otherwise, the commission's 47.33 order shall beis advisory and the order's findings and 47.34 conclusions shallconstitute prima facie evidence whichthat may 47.35 be rebutted by substantial evidence in all other proceedings. 47.36 With respect to utilities other than those defined in section 48.1 216B.02, subdivision 4, the commission shall consider the filing 48.2 requirements and decisions in any comparable proceedings in 48.3 another jurisdiction. As a part of its resource plan filing, a 48.4 utility shall include the least cost plan for meeting 50 and 75 48.5 percent of all new and refurbished capacity needs through a 48.6 combination of conservation and renewable energy resources. 48.7 Sec. 5. [452.25] [JOINT VENTURES BY UTILITIES.] 48.8 Subdivision 1. [APPLICABILITY.] This section applies to 48.9 all home rule charter and statutory cities, except as provided 48.10 in section 6. 48.11 Subd. 2. [DEFINITIONS.] For purposes of this section: 48.12 (a) "City" means a statutory or home rule charter city, 48.13 section 410.015 to the contrary notwithstanding. 48.14 (b) "Cooperative association" means a cooperative 48.15 association organized under chapter 308A. 48.16 (c) "Governing body" means (1) the city council in a city 48.17 that operates a municipal utility, or (2) a board, commission, 48.18 or body empowered by law, city charter, or ordinance or 48.19 resolution of the city council to control and operate the 48.20 municipal utility. 48.21 (d) "Investor-owned utility" means an entity that provides 48.22 utility services to the public under chapter 216B and that is 48.23 owned by private persons. 48.24 (e) "Municipal power agency" means an organization created 48.25 under sections 453.51 to 453.62. 48.26 (f) "Municipal utility" means a utility owned, operated, or 48.27 controlled by a city to provide utility services. 48.28 (g) "Public utility" or "utility" means a provider of 48.29 electric or water facilities or services or an entity engaged in 48.30 other similar or related operations authorized by law or charter. 48.31 Subd. 3. [AUTHORITY.] (a) Upon the approval of its elected 48.32 utilities commission or, if there be none, its city council, a 48.33 municipal utility may enter into a joint venture with other 48.34 municipal utilities, municipal power agencies, cooperative 48.35 associations, or investor-owned utilities to provide utility 48.36 services. Retail electric utility services provided by a joint 49.1 venture must be within the boundaries of each utility's 49.2 exclusive electric service territory as shown on the map of 49.3 service territories maintained by the department of commerce. 49.4 The terms and conditions of the joint venture are subject to 49.5 ratification by the governing bodies of the respective utilities 49.6 and may include the formation of a corporate or other separate 49.7 legal entity with an administrative and governance structure 49.8 independent of the respective utilities. 49.9 (b) A corporate or other separate legal entity, if formed: 49.10 (1) has the authority and legal capacity and, in the 49.11 exercise of the joint venture, the powers, privileges, 49.12 responsibilities, and duties authorized by this section; 49.13 (2) is subject to the laws and rules applicable to the 49.14 organization, internal governance, and activities of the entity; 49.15 (3) in connection with its property and affairs and in 49.16 connection with property within its control, may exercise any 49.17 and all powers that may be exercised by a natural person or a 49.18 private corporation or other private legal entity in connection 49.19 with similar property and affairs; and 49.20 (4) a joint venture that does not include an investor-owned 49.21 utility may elect to be deemed a municipal utility or a 49.22 cooperative association for purposes of chapter 216B or other 49.23 federal or state law regulating utility operations; and 49.24 (5) a joint venture that includes an investor-owned utility 49.25 must notify the public utilities commission 30 days in advance 49.26 of offering services. Upon a finding by the commission, such 49.27 joint venture will be subject to regulation under chapter 216B. 49.28 (c) Any corporation, if formed, must comply with section 49.29 465.719, subdivisions 9, 10, 11, 12, 13, and 14. The term 49.30 "political subdivision," as it is used in section 465.719, shall 49.31 refer to the city council of a city. 49.32 Subd. 4. [RETAIL CUSTOMERS.] Unless the joint venture's 49.33 retail electric rates, as defined in section 216B.02, 49.34 subdivision 5, of a joint venture that does not include an 49.35 investor-owned utility, are approved by the governing body of 49.36 each municipal utility or municipal power agency and the board 50.1 of directors of each cooperative association that is party to 50.2 the joint venture, the retail electric customers of the joint 50.3 venture, if their number be more than 25, may elect to become 50.4 subject to electric rate regulation by the public utilities 50.5 commission as provided in chapter 216B. The election is subject 50.6 to and must be carried out according to the procedures in 50.7 section 216B.026 and, for these purposes, each retail electric 50.8 customer of the joint venture is deemed a member or stockholder 50.9 as referred to in section 216B.026. 50.10 Subd. 5. [POWERS.] (a) A joint venture under this section 50.11 has the powers, privileges, responsibilities, and duties of the 50.12 separate utilities entering into the joint venture as the joint 50.13 venture agreement may provide, including the powers under 50.14 paragraph (b), except that: 50.15 (1) with respect to retail electric utility services, a 50.16 joint venture shall not enlarge or extend the service territory 50.17 served by the joint venture by virtue of the authority granted 50.18 in sections 216B.44, 216B.45, and 216B.47; 50.19 (2) a joint venture may extend service to an existing 50.20 connected load of 2,000 kilowatts or more, pursuant to section 50.21 216B.42, when the load is outside of the assigned service area 50.22 of the joint venture, or of the electric utilities party to the 50.23 joint venture, only if the load is already being served by one 50.24 of the electric utilities party to the joint venture; and 50.25 (3) a privately owned utility, as defined in section 50.26 216B.02, may extend service to an existing connected load of 50.27 2,000 kilowatts or more, pursuant to section 216B.42, when the 50.28 load is located within the assigned service territory of the 50.29 joint venture, or of the electric utilities party to the joint 50.30 venture, only if the load is already being served by that 50.31 privately owned utility. 50.32 The limitations of clauses (1) to (3) do not apply if written 50.33 consent to the action is obtained from the electric utility 50.34 assigned to and serving the affected service territory or 50.35 connected load. 50.36 (b) Joint venture powers include, but are not limited to, 51.1 the authority to: 51.2 (1) finance, own, acquire, construct, and operate 51.3 facilities necessary to provide utility services to retail 51.4 customers of the joint venture, including generation, 51.5 transmission, and distribution facilities, and like facilities 51.6 used in other utility services; 51.7 (2) combine assigned service territories, in whole or in 51.8 part, upon notice to, hearing by, and approval of the public 51.9 utilities commission; 51.10 (3) serve customers in the utilities' service territories 51.11 or in the combined service territory; 51.12 (4) combine, share, or employ administrative, managerial, 51.13 operational, or other staff if combining or sharing will not 51.14 degrade safety, reliability, or customer service standards; 51.15 (5) provide for joint administrative functions, such as 51.16 meter reading and billings; 51.17 (6) purchase or sell utility services at wholesale for 51.18 resale to customers; 51.19 (7) provide conservation programs, other utility programs, 51.20 and public interest programs, such as cold weather shut-off 51.21 protection and conservation spending programs, as required by 51.22 law and rule; and 51.23 (8) participate as the parties deem necessary in providing 51.24 utility services with other municipal utilities, cooperative 51.25 utilities, investor-owned utilities, or other entities, public 51.26 or private. 51.27 (c) Notwithstanding any contrary provision within this 51.28 section, a joint venture formed under this section may engage in 51.29 wholesale utility services unless the municipal utility, 51.30 municipal power agency, cooperative association, or 51.31 investor-owned utility party to the joint venture is prohibited 51.32 under current law from conducting that activity; but, in any 51.33 case, the joint venture may provide wholesale services to a 51.34 municipal utility, a cooperative association, or an 51.35 investor-owned utility that is party to the joint venture. 51.36 (d) This subdivision does not limit the authority of a 52.1 joint venture to exercise rights of eminent domain for other 52.2 utility purposes to the same extent as is permitted of those 52.3 utilities party to the joint venture. 52.4 Subd. 6. [CONSTRUCTION.] (a) The powers conferred by this 52.5 section are in addition to the powers conferred by other law or 52.6 charter. A joint venture under this section, and a municipal 52.7 utility with respect to any joint venture under this section, 52.8 have the powers necessary to effect the intent and purpose of 52.9 this section, including, but not limited to, the expenditure of 52.10 public funds and the transfer of real or personal property in 52.11 accordance with the terms and conditions of the joint venture 52.12 and the joint venture agreement. This section is complete in 52.13 itself with respect to the formation and operation of a joint 52.14 venture under this section and with respect to a municipal 52.15 utility, a cooperative association, or an investor-owned utility 52.16 party to a joint venture related to their creation of and 52.17 dealings with the joint venture, without regard to other laws or 52.18 city charter provisions that do not specifically address or 52.19 refer to this section or a joint venture created under this 52.20 section. 52.21 (b) This section must not be construed to supersede or 52.22 modify: 52.23 (1) the power of a city council conferred by charter to 52.24 overrule or override any action of a governing body other than 52.25 the actions of the joint venture; 52.26 (2) chapter 216B; 52.27 (3) any referendum requirements applicable to the creation 52.28 of a new electric utility by a municipality under section 52.29 216B.46 or 216B.465; or 52.30 (4) any powers, privileges, or authority or any duties or 52.31 obligations of a municipal utility, municipal power agency, or 52.32 cooperative association acting as a separate legal entity 52.33 without reference to a joint venture created under this section. 52.34 Sec. 6. [EXCEPTION.] 52.35 Laws 1996, chapter 300, section 1, as amended by Laws 1997, 52.36 chapter 232, section 1, govern joint ventures created under it 53.1 and those joint ventures are not governed by this section. 53.2 Sec. 7. [EXEMPTION EXTENDED.] 53.3 The commissioner of commerce shall not review the exemption 53.4 under Minnesota Statutes, section 216B.241, subdivision 1a, 53.5 paragraph (b), of a large electric customer facility, as defined 53.6 in Minnesota Statutes, section 216B.241, subdivision 1, 53.7 paragraph (g), from the investment and expenditure requirements 53.8 of Minnesota Statutes, section 216B.241, subdivision 1a, 53.9 paragraph (b), for five years from the date the exemption was 53.10 granted, provided the exemption was granted before April 15, 53.11 2001. This provision does not apply if the customer facility's 53.12 peak electrical demand exceeds ten percent of the peak 53.13 electrical demand of the facility as of the date the exemption 53.14 was granted. 53.15 Sec. 8. [EFFECTIVE DATE.] 53.16 This article is effective the day following final enactment. 53.17 ARTICLE 4 53.18 INTERCONNECTION OF DISTRIBUTED RESOURCES 53.19 Section 1. [216B.68] [DEFINITIONS.] 53.20 Subdivision 1. [SCOPE.] The words and terms used in 53.21 sections 216B.68 to 216B.75 have the meanings given them in this 53.22 section. 53.23 Subd. 2. [APPLICATION FOR INTERCONNECTION AND PARALLEL 53.24 OPERATION.] "Application for interconnection and parallel 53.25 operation" with the utility system or application means a 53.26 standard form of application developed by the commissioner and 53.27 approved by the commission. 53.28 Subd. 3. [COMPANY.] "Company" means an electric utility 53.29 operating a distribution system. 53.30 Subd. 4. [ELECTRIC UTILITY.] "Electric utility" means all 53.31 electric utilities that own and operate equipment in the state 53.32 for furnishing electric service at retail. 53.33 Subd. 5. [CUSTOMER.] "Customer" means any individual 53.34 person or entity interconnected to the company's utility system 53.35 for the purpose of receiving or exporting electric power from or 53.36 to the company's utility system. 54.1 Subd. 6. [DISTRIBUTED GENERATION OR ON-SITE DISTRIBUTED 54.2 GENERATION.] "Distributed generation" or "on-site distributed 54.3 generation" means an electrical generating facility located at a 54.4 customer's point of delivery or point of common coupling of ten 54.5 megawatts or less and connected at a voltage less than or equal 54.6 to 60 kilovolts that may be connected in parallel operation to 54.7 the utility system. 54.8 Subd. 7. [FACILITY.] "Facility" means an electrical 54.9 generating installation consisting of one or more on-site 54.10 distributed generation units. The total capacity of a 54.11 facility's individual on-site distributed generation units may 54.12 exceed ten megawatts; however, no more than ten megawatts of a 54.13 facility's capacity will be interconnected at any point in time 54.14 at the point of common coupling under this section. 54.15 Subd. 8. [INTERCONNECTION.] "Interconnection" means the 54.16 physical connection of distributed generation to the utility 54.17 system in accordance with the requirements of this section so 54.18 that parallel operation can occur. 54.19 Subd. 9. [INTERCONNECTION AGREEMENT.] "Interconnection 54.20 agreement" means the standard form of agreement, developed and 54.21 approved by the commission. The interconnection agreement sets 54.22 forth the contractual conditions under which a company and a 54.23 customer agree that one or more facilities may be interconnected 54.24 with the company's utility system. 54.25 Subd. 10. [PARALLEL OPERATION.] "Parallel operation" means 54.26 the operation of on-site distributed generation by a customer 54.27 while the customer is connected to the company's utility system. 54.28 Subd. 11. [POINT OF COMMON COUPLING.] "Point of common 54.29 coupling" means the point where the electrical conductors of the 54.30 company utility system are connected to the customer's 54.31 conductors and where any transfer of electric power between the 54.32 customer and the utility system takes place, such as switchgear 54.33 near the meter. 54.34 Subd. 12. [PRECERTIFIED EQUIPMENT.] "Precertified 54.35 equipment" means a specific generating and protective equipment 54.36 system or systems that have been certified as meeting the 55.1 applicable parts of this section relating to safety and 55.2 reliability by an entity approved by the commission. 55.3 Subd. 13. [PRE-INTERCONNECTION 55.4 STUDY.] "Pre-interconnection study" means a study or studies 55.5 that may be undertaken by a company in response to its receipt 55.6 of a completed application for interconnection and parallel 55.7 operation with the utility system. Pre-interconnection studies 55.8 may include, but are not limited to, service studies, 55.9 coordination studies, and utility system impact studies. 55.10 Sec. 2. [216B.69] [INTERCONNECTION OF ON-SITE DISTRIBUTED 55.11 GENERATION.] 55.12 Subdivision 1. [PURPOSE.] The purpose of this section is 55.13 to: 55.14 (1) establish the terms and conditions that govern the 55.15 interconnection and parallel operation of on-site distributed 55.16 generation; 55.17 (2) provide cost savings and reliability benefits to 55.18 customers; 55.19 (3) establish technical requirements that will promote the 55.20 safe and reliable parallel operation of on-site distributed 55.21 generation resources; 55.22 (4) enhance both the reliability of electric service and 55.23 economic efficiency in the production and consumption of 55.24 electricity; and 55.25 (5) promote the use of distributed resources in order to 55.26 provide electric system benefits during periods of capacity 55.27 constraints. 55.28 Subd. 2. [DISTRIBUTED GENERATION; GENERIC PROCEEDING.] (a) 55.29 The commission shall initiate a proceeding within 30 days of the 55.30 effective date of this section, to establish, by order, generic 55.31 standards for utility tariffs for the interconnection and 55.32 parallel operation of distributed generation of no more than ten 55.33 megawatts of interconnected capacity. The commission shall 55.34 ensure that these standards are, and continue to be, consistent 55.35 with federal requirements and any distributed generation 55.36 interconnection operational and safety standards adopted by the 56.1 institute of electrical and electronics engineers, and must: 56.2 (1) provide for the low-cost, safe, and standardized 56.3 interconnection of facilities fueled by natural gas, by a 56.4 renewable fuel, by another similarly clean fuel, or by a 56.5 combination of these fuels, which may include, but are not 56.6 limited to, fuel cells, microturbines, wind turbines, or solar 56.7 modules; 56.8 (2) take into account differing system requirements and 56.9 hardware, as well as the overall demand load requirements of 56.10 individual utilities; 56.11 (3) encourage and compensate for the addition of 56.12 distributed generation power resources while reducing the cost 56.13 to the utility's customers for energy, capacity, transmission, 56.14 and distribution; 56.15 (4) minimize and avoid increases in the rates of other 56.16 customers on the utility's system; 56.17 (5) allow for reasonable terms and conditions, consistent 56.18 with the cost and operating characteristics of the various 56.19 technologies, so that a utility can reasonably be assured of the 56.20 reliable, safe, and efficient operation of the interconnected 56.21 equipment; 56.22 (6) ensure that backup power, supplemental power, and 56.23 maintenance power are available to all customers and customer 56.24 classes that desire this service; 56.25 (7) establish a standard interconnection agreement that 56.26 sets forth the contractual conditions under which a company and 56.27 a customer agree that one or more facilities may be 56.28 interconnected with the company's utility system; and 56.29 (8) establish a standard application for interconnection 56.30 and parallel operation with the utility system. 56.31 (b) The commission may develop financial incentives based 56.32 on a public utility's performance in encouraging residential and 56.33 small business customers to participate in on-site generation. 56.34 Subd. 3. [DISTRIBUTED GENERATION TARIFF.] Within 90 days 56.35 of the issuance of an order under subdivision 2: 56.36 (1) each public utility providing electric service at 57.1 retail shall file a distributed generation tariff consistent 57.2 with that order, for commission approval or approval with 57.3 modification; and 57.4 (2) each municipal utility and cooperative electric 57.5 association shall adopt a distributed generation tariff that 57.6 addresses the issues included in the commission's order. 57.7 Sec. 3. [216B.70] [DISCONNECTION AND RECONNECTION.] 57.8 Subdivision 1. [WHEN DISCONNECTION ALLOWED.] A utility may 57.9 disconnect a distributed generation unit from the utility system 57.10 if: 57.11 (1) the interconnection agreement with a customer expires 57.12 or terminates, in accordance with the terms of the agreement; 57.13 (2) the facility is not in compliance with the technical 57.14 requirements specified by the commissioner; 57.15 (3) continued interconnection will endanger persons or 57.16 property; or 57.17 (4) written notice is provided at least seven business days 57.18 prior to a service interruption for routine maintenance, 57.19 repairs, and utility system modifications. 57.20 Subd. 2. [INCREMENTAL DEMAND CHARGES.] During the term of 57.21 an interconnection agreement, a utility may require that a 57.22 customer disconnect its distributed generation unit or take it 57.23 off-line as a result of utility system conditions. The company 57.24 may not assess the customer incremental demand charges arising 57.25 from disconnecting the distributed generator as directed by the 57.26 company during these periods. 57.27 Sec. 4. [216B.71] [PRE-INTERCONNECTION STUDIES FOR 57.28 NONNETWORK INTERCONNECTION OF DISTRIBUTED GENERATION.] 57.29 Subdivision 1. [STUDIES.] A utility may conduct a service 57.30 study, coordination study, or utility system impact study prior 57.31 to interconnection of a distributed generation facility. When a 57.32 study is deemed necessary, the scope of the study must be based 57.33 on the characteristics of the particular distributed generation 57.34 facility to be interconnected and the utility's system at the 57.35 specific proposed location. At the customer's choice, a study 57.36 related to interconnection of distributed generation on the 58.1 customer's premises may be conducted by a qualified third party 58.2 jointly selected by the utility and the customer. 58.3 Subd. 2. [CUSTOMER FEE.] A utility generation facility not 58.4 described in subdivision 1 may charge a customer a fee to offset 58.5 its costs incurred in the conduct of a pre-interconnection study. 58.6 Subd. 3. [WHEN UTILITY CONDUCTS STUDY.] When a utility 58.7 conducts an interconnection study, paragraphs (a) to (d) apply: 58.8 (a) The conduct of the pre-interconnection study may not 58.9 take more than four weeks. 58.10 (b) A utility shall prepare written reports of the study 58.11 findings and make them available to the customer. 58.12 (c) The study must consider both the costs incurred and the 58.13 benefits realized as a result of the interconnection of 58.14 distributed generation to the company's utility system. 58.15 (d) The utility shall provide the customer with an estimate 58.16 of the study cost before the utility initiates the study. 58.17 Sec. 5. [216B.72] [PRE-INTERCONNECTION STUDIES FOR NETWORK 58.18 INTERCONNECTION OF DISTRIBUTED GENERATION.] 58.19 Subdivision 1. [NOTICE AND FEES.] Prior to charging a 58.20 pre-interconnection study fee for a network interconnection of 58.21 distributed generation, a utility shall first advise the 58.22 customer of the potential problems associated with 58.23 interconnection of distributed generation with its network 58.24 system. 58.25 Subd. 2. [REQUIREMENTS WHEN UTILITY CONDUCTS STUDY.] When 58.26 a utility conducts an interconnection study, paragraphs (a) to 58.27 (d) apply: 58.28 (a) The conduct of a pre-interconnection study may not take 58.29 more than four weeks. 58.30 (b) A utility shall prepare written reports of the study 58.31 findings and make them available to the customer. 58.32 (c) The study must consider both the costs incurred and the 58.33 benefits realized as a result of the interconnection of 58.34 distributed generation to the utility's system. 58.35 (d) The utility shall provide the customer with an estimate 58.36 of the study cost before the utility initiates the study. 59.1 Sec. 6. [216B.73] [EQUIPMENT PRECERTIFICATION.] 59.2 (a) The commissioner may approve one or more entities that 59.3 shall precertify equipment as described under this section. 59.4 (b) Testing organizations or facilities capable of 59.5 analyzing the function, control, and protective systems of 59.6 distributed generation units may request to be certified as 59.7 testing organizations. 59.8 (c) Distributed generation units that are certified to be 59.9 in compliance by an approved testing facility or organization 59.10 must be installed on a company utility system in accordance with 59.11 an approved interconnection control and protection scheme 59.12 without further review of their design by the utility. 59.13 Sec. 7. [216B.74] [TIME FOR PROCESSING APPLICATIONS FOR 59.14 INTERCONNECTION.] 59.15 (a) The interconnection of distributed generation to the 59.16 utility system must take place within the schedules described in 59.17 paragraphs (b) to (f): 59.18 (b) For a facility with precertified equipment, 59.19 interconnection must take place within four weeks of the 59.20 utility's receipt of a completed interconnection application. 59.21 (c) For facilities without precertified equipment, 59.22 connection must take place within six weeks of the utility's 59.23 receipt of a completed application. 59.24 (d) If interconnection of a particular facility will 59.25 require substantial capital upgrades to the utility system, the 59.26 company shall provide the customer an estimate of the schedule 59.27 and the customer's cost for the upgrade. If the customer 59.28 desires to proceed with the upgrade, the customer and the 59.29 company shall enter into a contract for the completion of the 59.30 upgrade. The interconnection must take place no later than two 59.31 weeks following the completion of the upgrade. The utility 59.32 shall employ best reasonable efforts to complete the system 59.33 upgrade in the shortest time reasonably practical. 59.34 (e) A utility shall use best reasonable efforts to 59.35 interconnect facilities within the time frames described in this 59.36 section. If in a particular instance, a utility determines that 60.1 it cannot interconnect a facility within the time frames stated 60.2 in this section, it must notify the applicant in writing of that 60.3 fact. The notification must identify any reasons 60.4 interconnection could not be performed in accordance with the 60.5 schedule and provide an estimated date for interconnection. 60.6 (f) Applications for interconnection and parallel operation 60.7 of distributed generation must be processed by the utility in a 60.8 nondiscriminatory manner and in the order that they are 60.9 received. It is recognized that certain applications may 60.10 require minor modifications while they are being reviewed by the 60.11 utility. These minor modifications to a pending application do 60.12 not require that it be considered incomplete and treated as a 60.13 new or separate application. 60.14 Sec. 8. [216B.75] [REPORTING REQUIREMENTS.] 60.15 (a) Each electric utility shall maintain records concerning 60.16 applications received for interconnection and parallel operation 60.17 of distributed generation. The records must include the date 60.18 each application is received, documents generated in the course 60.19 of processing each application, correspondence regarding each 60.20 application, and the final disposition of each application. 60.21 (b) As part of the reporting requirement under section 60.22 216C.052, subdivision 4, every electric utility shall file with 60.23 the reliability administrator a distributed generation 60.24 interconnection report for the preceding calendar year that 60.25 identifies each distributed generation facility interconnected 60.26 with the utility's distribution system. The report must list 60.27 the new distributed generation facilities interconnected with 60.28 the system since the previous year's report, any distributed 60.29 generation facilities no longer interconnected with the 60.30 utility's system since the previous report, the capacity of each 60.31 facility, and the feeder or other point on the company's utility 60.32 system where the facility is connected. The annual report must 60.33 also identify all applications for interconnection received 60.34 during the previous one-year period, and the disposition of the 60.35 applications. 60.36 Sec. 9. [EFFECTIVE DATE.] 61.1 This article is effective the day following final enactment. 61.2 ARTICLE 5 61.3 CONFORMING AMENDMENTS 61.4 Section 1. Minnesota Statutes 2000, section 116C.61, 61.5 subdivision 1, is amended to read: 61.6 Subdivision 1. [ REGIONAL, COUNTY AND LOCAL ORDINANCES,61.7 RULES, REGULATIONS;PRIMARY RESPONSIBILITY ANDREGULATION OF 61.8 SITE DESIGNATION, IMPROVEMENT, AND USE.] To assure the paramount 61.9 and controlling effect of the provisions hereinthis section 61.10 over other state agencies ,; regional, county, and local 61.11 governments ,; and special purpose government districts, the 61.12 issuance of a certificate ofsite compatibilitypermit or 61.13 transmission line constructionroute permit and subsequent 61.14 purchase and use of suchsite or route locations for large 61.15 electric power generating plant and high voltage transmission 61.16 line purposes shall beis the sole site approval required to be 61.17 obtained by the utility. Such certificate orThe permit shall61.18 supersedesupersedes and preempt allpreempts any zoning, 61.19 building, or land use rules, regulations, or ordinances 61.20 promulgated by any regional, county, local, and special purpose 61.21 government. 61.22 Sec. 2. Minnesota Statutes 2000, section 116C.62, is 61.23 amended to read: 61.24 116C.62 [IMPROVEMENT OF SITES AND ROUTES.] 61.25 Utilities whichthat have acquired a site or route in 61.26 accordance with sections 116C.51 to 116C.69 may proceed to 61.27 construct or improve the site or route for the intended purposes 61.28 at any time, subject to section 116C.61, subdivision 2 ,; 61.29 provided that, if the construction and improvement commences61.30 more thanhas not commenced within four years after a 61.31 certificate orpermit for the site or route has been issued, 61.32 then the utility must certify to the board that the site or 61.33 route continues to meet the conditions upon which the 61.34 certificate of site compatibility or transmission line 61.35 construction permit was issued. 61.36 Sec. 3. Minnesota Statutes 2000, section 116C.64, is 62.1 amended to read: 62.2 116C.64 [FAILURE TO ACT.] 62.3 If the board fails to act within the times specified in 62.4 section 116C.57, the applicant or any affected utilityperson 62.5 may seek an order of the district court requiring the board to 62.6 designate or refuse to designate a site or route. 62.7 Sec. 4. Minnesota Statutes 2000, section 116C.645, is 62.8 amended to read: 62.9 116C.645 [REVOCATION OR SUSPENSION.] 62.10 A site certificatepermit or constructionroute permit may 62.11 be revoked or suspended by the board after adequate notice of 62.12 the alleged grounds for revocation or suspension and a full and 62.13 fair hearing in which the affected utility has an opportunity to 62.14 confront any witness and respond to any evidence against it and 62.15 to present rebuttal or mitigating evidence upon a finding by the 62.16 board of: 62.17 (1) any false statement knowingly made in the application 62.18 or in accompanying statements or studies required of the 62.19 applicant, if a true statement would have warranted a change in 62.20 the board's findings; 62.21 (2) failure to comply with material conditions of the site 62.22 certificate or construction permit, or failure to maintain 62.23 health and safety standards; or 62.24 (3) any material violation of the provisions of sections 62.25 116C.51 to 116C.69, any rule promulgated pursuant thereto62.26 adopted under these sections, or any order of the board. 62.27 Sec. 5. Minnesota Statutes 2000, section 116C.65, is 62.28 amended to read: 62.29 116C.65 [JUDICIAL REVIEW.] 62.30 Any utilityapplicant, party, or person aggrieved by the 62.31 issuance of a certificatesite or route permit or emergency 62.32 certificate of site compatibility or transmission line62.33 constructionpermit from the board or a certification of 62.34 continuing suitability filed by a utility with the board or by a 62.35 final order in accordance with any rules promulgatedadopted by 62.36 the board, may appeal to the court of appeals in accordance with 63.1 chapter 14. The appeal shallmust be filed within 60 days after 63.2 the publication in the State Register of notice of the issuance 63.3 of the certificate or permit by the board or certification filed 63.4 with the board or the filing of any final order by the board. 63.5 Sec. 6. Minnesota Statutes 2000, section 116C.66, is 63.6 amended to read: 63.7 116C.66 [RULES.] 63.8 (a) The board, in order to give effect to the purposes of 63.9 sections 116C.51 to 116C.69, shall prior to July 1, 1978,may 63.10 adopt rules consistent with sections 116C.51 to 116C.69, 63.11 including promulgationadoption of site and route designation 63.12 criteria ,; the description of the information to be furnished by 63.13 the utilities ,; establishment of minimum guidelines for public 63.14 participation in the development, revision, and enforcement of 63.15 any rule, plan, or program established by the board ,; procedures 63.16 for the revocation or suspension of a construction permit or a 63.17 certificate of site compatibility ,; the procedure and timeliness 63.18 for proposing alternative routes and sites ,; and route exemption 63.19 criteria and procedures. 63.20 No(b) A rule adopted by the board shallmay not grant 63.21 priority to state-owned wildlife management areas over 63.22 agricultural lands in the designation of route-avoidance areas. 63.23 (c) The provisions of chapter 14 shallapply to the appeal 63.24 of rules adopted by the board to the same extent as it applies 63.25 to the review of rules adopted by any other agency of state 63.26 government. 63.27 (d) The chief administrative law judge shall , prior to63.28 January 1, 1978,adopt procedural rules for public hearings 63.29 relating to the site and route designation process and to the 63.30 route exemption process. The rules shallmust attempt to 63.31 maximize citizen participation in these processes. 63.32 Sec. 7. Minnesota Statutes 2000, section 116C.69, is 63.33 amended to read: 63.34 116C.69 [ BIENNIAL REPORT;APPLICATION FEES; APPROPRIATION; 63.35 FUNDING.] 63.36 Subdivision 1. [BIENNIAL REPORT.] Before November 15 of 64.1 each even-numbered year the board shall prepare and submit to 64.2 the legislature a report of its operations, activities, 64.3 findings, and recommendations concerning sections 116C.51 to 64.4 116C.69. The report shall also contain information on the 64.5 board's biennial expenditures, its proposed budget for the 64.6 following biennium, and the amounts paid in certificate and64.7 permit application fees pursuant to subdivisions 2 and 2aand in 64.8 assessments pursuant to subdivision 3this section. The 64.9 proposed budget for the following biennium shall beis subject 64.10 to legislative review. 64.11 Subd. 2. [SITE APPLICATION FEE.] Every applicant for a 64.12 site certificatepermit shall pay to the board a fee in an 64.13 amount equal to $500 for each $1,000,000 of production plant 64.14 investment in the proposed installation as defined in the 64.15 Federal Power Commission Uniform System of Accounts. The board 64.16 shall specify the time and manner of payment of the fee. If any 64.17 single payment requested by the board is in excess of 25 percent 64.18 of the total estimated fee, the board shall show that the excess 64.19 is reasonably necessary. The applicant shall pay within 30 days 64.20 of notification any additional fees reasonably necessary for 64.21 completion of the site evaluation and designation process by the 64.22 board. In no event shallThe total fees required of the 64.23 applicant under this subdivision must never exceed an amount 64.24 equal to 0.001 of saidthe production plant investment (, which 64.25 equals $1,000 for each $1,000,000 ). All money received pursuant64.26 tounder this subdivision shallmust be deposited in a special 64.27 account. Money in the account is appropriated to the board to 64.28 pay expenses incurred in processing applications 64.29 for certificatessite permits in accordance with sections 64.30 116C.51 to 116C.69 and in the event, if the expenses are less 64.31 than the fee paid, to refund the excess to the applicant. 64.32 Subd. 2a. [ROUTE APPLICATION FEE.] Every applicant for a 64.33 transmission line constructionroute permit shall pay to the 64.34 board a base fee of $35,000 plus a fee in an amount equal to 64.35 $1,000 per mile length of the longest proposed route. The board 64.36 shall specify the time and manner of payment of the fee. If any 65.1 single payment requested by the board is in excess of 25 percent 65.2 of the total estimated fee, the board shall show that the excess 65.3 is reasonably necessary. In the eventIf the actual cost of 65.4 processing an application up to the board's final decision to 65.5 designate a route exceeds the abovethis fee schedule, the board 65.6 may assess the applicant any additional fees necessary to cover 65.7 the actual costs, not to exceed an amount equal to $500 per mile 65.8 length of the longest proposed route. All money received 65.9 pursuant tounder this subdivision shallmust be deposited in a 65.10 special account. Money in the account is appropriated to the 65.11 board to pay expenses incurred in processing applications for 65.12 constructionroute permits in accordance with sections 116C.51 65.13 to 116C.69 and in the event, if the expenses are less than the 65.14 fee paid, to refund the excess to the applicant. 65.15 Subd. 3. [FUNDING; ASSESSMENT.] (a) The board shall 65.16 finance its base line studies, general environmental studies, 65.17 development of criteria, inventory preparation, monitoring of 65.18 conditions placed on site certificatesand constructionroute 65.19 permits, and all other work, other than specific site and route 65.20 designation, from an assessment made quarterly, at least 30 days 65.21 before the start of each quarter, by the board against all 65.22 utilities with annual retail kilowatt-hour sales greater than 65.23 4,000,000 kilowatt-hours in the previous calendar year. 65.24 (b) Each share shallmust be determined as follows: 65.25 (1) the ratio that the annual retail kilowatt-hour sales in 65.26 the state of each utility bears to the annual total retail 65.27 kilowatt-hour sales in the state of all these utilities, 65.28 multiplied by 0.667 ,; plus 65.29 (2) the ratio that the annual gross revenue from retail 65.30 kilowatt-hour sales in the state of each utility bears to the 65.31 annual total gross revenues from retail kilowatt-hour sales in 65.32 the state of all these utilities, multiplied by 0.333, as 65.33 determined by the board. 65.34 (c) The assessment shallmust be credited to the special 65.35 revenue fund and shall bepaid to the state treasury within 30 65.36 days after receipt of the bill, which shall constitute notice of 66.1 saidthe assessment and its demand of payment thereof. 66.2 (d) The total amount whichthat may be assessed to the 66.3 several utilities under the authority of this subdivision shall66.4 may not exceed the sum of the annual budget of the board for 66.5 carrying out the purposes of this subdivision. 66.6 (e) The assessment for the second quarter of each fiscal 66.7 year shallmust be adjusted to compensate for the amount by 66.8 which actual expenditures by the board for the preceding fiscal 66.9 year were more or less than the estimated expenditures 66.10 previously assessed. 66.11 Sec. 8. [INSTRUCTION TO REVISOR.] 66.12 (a) The revisor of statutes shall renumber Minnesota 66.13 Statutes, section 116C.69, subdivision 1, as Minnesota Statutes, 66.14 section 116C.681. 66.15 (b) The revisor of statutes shall change all references as 66.16 appropriate from Minnesota Statutes, section 216B.241 to 66.17 Minnesota Statutes, section 216B.2411, including references to 66.18 appropriate subdivisions, if known, in this act and in Minnesota 66.19 Statutes, chapters 216A, 216B, and 216C, and in the Minnesota 66.20 Rules associated with those chapters. 66.21 Sec. 9. [EFFECTIVE DATE.] 66.22 This article is effective the day following final enactment. 66.23 ARTICLE 6 66.24 MISCELLANEOUS PROVISIONS 66.25 Section 1. Minnesota Statutes 2000, section 216A.03, 66.26 subdivision 3a, is amended to read: 66.27 Subd. 3a. [POWERS AND DUTIES OF CHAIR.] The chair shall be66.28 is the principal executive officer of the commission and shall 66.29 preside at meetings of the commission. The responsibilities of 66.30 the chair shall organizeinclude: 66.31 (1) organizing the work of the commission and may make; 66.32 (2) making assignments to commission members, appoint66.33 committees and giveas appropriate; 66.34 (3) appointing subcommittees; 66.35 (4) giving direction to the commission staff through the 66.36 executive secretary subject to the approval of the commission .; 67.1 (5) supervising the work of the executive secretary; and 67.2 (6) in coordination with the executive secretary, 67.3 participating in employment and termination decisions, including 67.4 representing the commission in grievance proceedings; addressing 67.5 employee complaints and grievances; developing and implementing 67.6 the agency budget; testifying before legislative committees and 67.7 working with legislators as requested; determining agency-wide 67.8 training needs and initiatives; implementing computer technology 67.9 updates; administering and implementing relations with the 67.10 department of commerce, the office of the attorney general, and 67.11 other agencies; and developing and implementing strategies for 67.12 the commission to adapt to rapid changes in the industries the 67.13 commission oversees. 67.14 Sec. 2. Minnesota Statutes 2000, section 216B.095, is 67.15 amended to read: 67.16 216B.095 [DISCONNECTION DURING COLD WEATHER.] 67.17 The commission shall amend its rules governing 67.18 disconnection of residential utility customers who are unable to 67.19 pay for utility service during cold weather to include the 67.20 following: 67.21 (1) coverage of customers whose household income is less 67.22 than 185 percent of the federal poverty level50 percent of the 67.23 state median income; 67.24 (2) a requirement that a customer who pays the utility at 67.25 least ten percent of the customer's income or the full amount of 67.26 the utility bill, whichever is less, in a cold weather month 67.27 cannot be disconnected during that month; 67.28 (3) that the ten percent figure in clause (2) must be 67.29 prorated between energy providers proportionate to each 67.30 provider's share of the customer's total energy costs where the 67.31 customer receives service from more than one provider; 67.32 (4) that a customer's household income does not include any67.33 amount received for energy assistance;67.34 (5)(4) verification of income by the local energy 67.35 assistance provider or the utility, unless the customer is 67.36 automatically eligible for protection against disconnection as a 68.1 recipient of any form of public assistance, including energy 68.2 assistance, that uses income eligibility in an amount at or 68.3 below the income eligibility in clause (1); and68.4 (6)(5) a requirement that the customer receive , from the68.5 local energy assistance provider or other entity, budget68.6 counseling and referralreferrals to energy assistance programs, 68.7 weatherization, conservation, or other programs likely to reduce 68.8 the customer's consumption ofenergy bills; 68.9 (6) a requirement that customers who have demonstrated an 68.10 inability to pay on forms for such purposes provided by the 68.11 utility, and who make reasonably timely payments to the utility 68.12 under a payment plan that considers the financial resources of 68.13 the household, cannot be disconnected from utility services from 68.14 October 15 to April 15. A customer who is receiving energy 68.15 assistance is deemed to have demonstrated an inability to pay. 68.16 For the purpose of clause (2), the "customer's income" means the 68.17 actual monthly income of the customer except for a customer who68.18 is normally employed only on a seasonal basis and whose annual68.19 income is over 135 percent of the federal poverty level, in68.20 which case the customer's income isor the average monthly 68.21 income of the customer computed on an annual calendar year 68.22 basis, whichever is less, and does not include any amount 68.23 received for energy assistance. 68.24 Sec. 3. Minnesota Statutes 2000, section 216B.097, 68.25 subdivision 1, is amended to read: 68.26 Subdivision 1. [APPLICATION; NOTICE TO RESIDENTIAL 68.27 CUSTOMER.] (a) A municipal utility or a cooperative electric 68.28 association must not disconnect the utility service of a 68.29 residential customer during the period between October 15 and 68.30 April 15 if the disconnection affects the primary heat source 68.31 for the residential unit when the following conditions are met: 68.32 (1) the disconnection would occur during the period between68.33 October 15 and April 15;68.34 (2)(1) the customer has declared inability to pay on forms 68.35 provided by the utility. For the purpose of this clause, a 68.36 customer that is receiving energy assistance is deemed to have 69.1 demonstrated an inability to pay; 69.2 (3)(2) the household income of the customer is less than 69.3 185 percent of the federal poverty level, as documented by the69.4 customer to the utility; and50 percent of the state median 69.5 income; 69.6 (3) verification of income may be conducted by the local 69.7 energy assistance provider or the utility, unless the customer 69.8 is automatically eligible for protection against disconnection 69.9 as a recipient of any form of public assistance, including 69.10 energy assistance, that uses income eligibility in an amount at 69.11 or below the income eligibility in clause (2); 69.12 (4) the customer'sa customer whose account is current for 69.13 the billing period immediately prior to October 15 or the69.14 customer has enteredwho, at any time, enters into a payment 69.15 schedule that considers the financial resources of the household 69.16 and is reasonably current with payments under the schedule; and 69.17 (5) the customer receives referrals to energy assistance 69.18 programs, and weatherization, conservation, or other programs to 69.19 reduce the customer's energy bills. 69.20 (b) A municipal utility or a cooperative electric 69.21 association must, between August 15 and October 15 of each year, 69.22 notify all residential customers of the provisions of this 69.23 section. 69.24 Sec. 4. [216B.098] [CUSTOMER PROTECTIONS.] 69.25 Subdivision 1. [APPLICABILITY.] This section applies to 69.26 residential customers of public utilities, municipal utilities, 69.27 and cooperative electric associations. 69.28 Subd. 2. [BUDGET BILLING PLANS.] A utility shall offer a 69.29 customer a budget billing plan for payment of charges for 69.30 service, including adequate notice to customers prior to 69.31 changing budget payment amounts. Municipal utilities having 69.32 3,000 or fewer customers are exempt from this requirement. 69.33 Municipal utilities having more than 3,000 customers shall 69.34 implement this requirement within two years of the effective 69.35 date of this chapter. 69.36 Subd. 3. [PAYMENT AGREEMENTS.] A utility shall offer a 70.1 payment agreement for the payment of arrears. 70.2 Subd. 4. [UNDERCHARGES.] A utility shall offer a payment 70.3 agreement to customers who have been undercharged if no culpable 70.4 conduct by the customer or resident of the customer's household 70.5 caused the undercharge. The agreement must cover a period equal 70.6 to the time over which the undercharge occurred. No interest or 70.7 delinquency fee may be charged under this agreement. 70.8 Subd. 5. [MEDICALLY NECESSARY EQUIPMENT.] A utility shall 70.9 reconnect or continue service to a customer's residence where a 70.10 medical emergency exists or where medical equipment requiring 70.11 electricity is necessary to sustain life is in use, provided 70.12 that the utility receives from a medical doctor written 70.13 certification, or initial certification by telephone and written 70.14 certification within five business days, that failure to 70.15 reconnect or continue service will impair or threaten the health 70.16 or safety of a resident of the customer's household. The 70.17 customer must enter into a payment agreement. 70.18 Subd. 6. [COMMISSION AUTHORITY.] The commission, or staff 70.19 designated by the commission, has the authority to order 70.20 resolutions of disputes involving alleged violations of this 70.21 chapter by a public utility or any other disputes involving 70.22 public utilities coming within its jurisdiction. 70.23 Sec. 5. Minnesota Statutes 2000, section 216B.16, 70.24 subdivision 15, is amended to read: 70.25 Subd. 15. [LOW-INCOME RATE PROGRAMS; REPORT.] (a) The 70.26 commission may consider ability to pay as a factor in setting 70.27 utility rates and may establish programs for low-income 70.28 residential ratepayers in order to ensure affordable, reliable, 70.29 and continuous service to low-income utility customers. The70.30 commission shall order a pilot program for at least one70.31 utility. In ordering pilot programs, the commission shall70.32 consider the following:70.33 (1) the potential for low-income programs to provide70.34 savings to the utility for all collection costs including but70.35 not limited to: costs of disconnecting and reconnecting70.36 residential ratepayers' service, all activities related to the71.1 utilities' attempt to collect past due bills, utility working71.2 capital costs, and any other administrative costs related to71.3 inability to pay programs and initiatives;71.4 (2) the potential for leveraging federal low-income energy71.5 dollars to the state; and71.6 (3) the impact of energy costs as a percentage of the total71.7 income of a low-income residential customer.71.8 (b) In determining the structure of the pilot utility71.9 program, the commission shall:71.10 (1) consult with advocates for and representatives of71.11 low-income utility customers, administrators of energy71.12 assistance and conservation programs, and utility71.13 representatives;71.14 (2) coordinate eligibility for the program with the state71.15 and federal energy assistance program and low-income residential71.16 energy programs, including weatherization programs; and71.17 (3) evaluate comprehensive low-income programs offered by71.18 utilities in other states.71.19 (c) The commission shall implement at least one pilot71.20 project by January 1, 1995, and shall allow a utility required71.21 to implement a pilot project to recover the net costs of the71.22 project in the utility's rates.71.23 (d) The commission, in conjunction with the commissioner of71.24 the department of public service and the commissioner of71.25 economic security, shall review low-income rate programs and71.26 shall report to the legislature by January 1, 1998. The report71.27 must include:71.28 (1) the increase in federal energy assistance money71.29 leveraged by the state as a result of this program;71.30 (2) the effect of the program on low-income customer's71.31 ability to pay energy costs;71.32 (3) the effect of the program on utility customer bad debt71.33 and arrearages;71.34 (4) the effect of the program on the costs and numbers of71.35 utility disconnections and reconnections and other costs71.36 incurred by the utility in association with inability to pay72.1 programs;72.2 (5) the ability of the utility to recover the costs of the72.3 low-income program without a general rate change;72.4 (6) how other ratepayers have been affected by this72.5 program;72.6 (7) recommendations for continuing, eliminating, or72.7 expanding the low-income pilot program; and72.8 (8) how general revenue funds may be utilized in72.9 conjunction with low-income programs.72.10 (b) The purpose of the low-income programs is to lower the 72.11 percentage of income that low-income households devote to energy 72.12 bills, to increase customer payments, and to lower utility costs 72.13 associated with customer account collection activities. In 72.14 ordering low-income programs, the commission may require 72.15 utilities to file program evaluations, including the effect of 72.16 the program on participant household energy burdens, the 72.17 coordination of other available low-income bill payment and 72.18 conservation resources, the effect of the program on service 72.19 disconnections, and the effect of the program on customer 72.20 payment behavior, utility collection costs, arrearages, and bad 72.21 debt. 72.22 Sec. 6. [216B.79] [PREVENTATIVE MAINTENANCE.] 72.23 (a) The commission has the authority to ensure that public 72.24 utilities are making adequate infrastructure investments and 72.25 undertaking sufficient preventative maintenance with regard to 72.26 generation, transmission, and distribution facilities. 72.27 (b) The commission may make appropriate adjustments in a 72.28 utility's rates through an automatic adjustment of charges under 72.29 section 216B.16, accelerated depreciation of capital costs, or 72.30 other appropriate mechanisms, or make a recommendation to the 72.31 Federal Energy Regulatory Commission to make an appropriate 72.32 adjustment in a utility's allowed rate of return on those 72.33 utilities' transmission facilities, to provide incentive and 72.34 offset the costs of new energy infrastructure facility 72.35 construction. 72.36 Sec. 7. Minnesota Statutes 2000, section 216C.41, 73.1 subdivision 5, is amended to read: 73.2 Subd. 5. [AMOUNT OF PAYMENT.] (a) An incentive payment is 73.3 based on the number of kilowatt hours of electricity generated. 73.4 The amount of the payment is 1.5 cents per kilowatt hour. For 73.5 electricity generated by qualified wind energy conversion 73.6 facilities, the incentive payment under this section is limited 73.7 to no more than 100 megawatts of nameplate capacity. During any 73.8 period in which qualifying claims for incentive payments exceed 73.9 100 megawatts of nameplate capacity, the payments must be made 73.10 to producers in the order in which the production capacity was 73.11 brought into production. 73.12 (b) Beginning January 1, 2002, the total size of a wind 73.13 energy conversion system under this section must be determined 73.14 according to this paragraph. Unless the systems are 73.15 interconnected with different distribution systems, the 73.16 nameplate capacity of one wind energy conversion system must be 73.17 combined with the nameplate capacity of any other wind energy 73.18 conversion system that is: 73.19 (1) located within five miles of the wind energy conversion 73.20 system; 73.21 (2) constructed within the same calendar year as the wind 73.22 energy conversion system; and 73.23 (3) under common ownership. 73.24 In the case of a dispute, the commissioner of commerce shall 73.25 determine the total size of the system, and shall draw all 73.26 reasonable inferences in favor of combining the systems. 73.27 (c) In making a determination under paragraph (b), the 73.28 commissioner of commerce may determine that two wind energy 73.29 conversion systems are under common ownership when the 73.30 underlying ownership structure contains similar persons or 73.31 entities, even if the ownership shares differ between the two 73.32 systems. Wind energy conversion systems are not under common 73.33 ownership solely because the same person or entity provided 73.34 equity financing for the systems. 73.35 Sec. 8. Minnesota Statutes 2000, section 216C.41, is 73.36 amended by adding a subdivision to read: 74.1 Subd. 6. [OWNERSHIP; FINANCING; CURE.] (a) For the 74.2 purposes of subdivision 1, paragraph (c), clause (2), a wind 74.3 energy conversion facility qualifies if it is owned at least 51 74.4 percent by one or more of any combination of the entities listed 74.5 in that clause. 74.6 (b) A subsequent owner of a qualified facility may continue 74.7 to receive the incentive payment for the duration of the 74.8 original payment period if the subsequent owner qualifies for 74.9 the incentive under subdivision 1. 74.10 (c) Nothing in this section may be construed to deny 74.11 incentive payment to an otherwise qualified facility that has 74.12 obtained debt or equity financing for construction or operation 74.13 as long as the ownership requirements of subdivision 1 and this 74.14 subdivision are met. If, during the incentive payment period 74.15 for a qualified facility, the owner of the facility is in 74.16 default of a lending agreement and the lender takes possession 74.17 of and operates the facility and makes reasonable efforts to 74.18 transfer ownership of the facility to an entity other than the 74.19 lender, the lender may continue to receive the incentive payment 74.20 for electricity generated and sold by the facility for a period 74.21 not to exceed 18 months. A lender who takes possession of a 74.22 facility shall notify the commissioner immediately on taking 74.23 possession and, at least quarterly, document efforts to transfer 74.24 ownership of the facility. 74.25 (d) If, during the incentive payment period, a qualified 74.26 facility loses the right to receive the incentive because of 74.27 changes in ownership, the facility may regain the right to 74.28 receive the incentive upon cure of the ownership structure that 74.29 resulted in the loss of eligibility and may reapply for the 74.30 incentive, but in no case may the payment period be extended 74.31 beyond the original ten-year limit. 74.32 (e) A subsequent or requalifying owner under paragraph (b) 74.33 or (d) retains the facility's original priority order for 74.34 incentive payments as long as the ownership structure 74.35 requalifies within two years from the date the facility became 74.36 unqualified or two years from the date a lender takes possession. 75.1 Sec. 9. [REPEALER.] 75.2 Minnesota Statutes 2000, sections 216B.241 and 216C.18 are 75.3 repealed. 75.4 Sec. 10. [EFFECTIVE DATE.] 75.5 This article is effective the day following final enactment. 75.6 ARTICLE 7 75.7 SAFETY AND SERVICE STANDARDS 75.8 Section 1. [216B.81] [DEFINITIONS.] 75.9 Subdivision 1. [SCOPE.] The terms used in this article 75.10 have the meanings given them in this section. 75.11 Subd. 2. [AVERAGE NUMBER OF CUSTOMERS SERVED.] "Average 75.12 number of customers served" means the number of active, metered, 75.13 customer accounts available in a utility's 75.14 interruption-reporting database on the day that an interruption 75.15 occurs. 75.16 Subd. 3. [CIRCUIT.] "Circuit" means a set of conductors 75.17 serving customer loads that are capable of being separated from 75.18 the serving substation automatically by a recloser, fuse, 75.19 sectionalizing equipment, and other devices. 75.20 Subd. 4. [COMPONENT.] "Component" means a piece of 75.21 equipment, a line, a section of line, or a group of items that 75.22 is an entity for purposes of reporting, analyzing, and 75.23 predicting interruptions. 75.24 Subd. 5. [CUSTOMER.] "Customer" means a contiguous 75.25 electrical service location, regardless of the number of meters 75.26 at the location. 75.27 Subd. 6. [CUSTOMER INTERRUPTION.] "Customer interruption" 75.28 means the loss of service due to a forced outage for more than 75.29 five minutes, for one or more customers, which is the result of 75.30 one or more component failures. 75.31 Subd. 7. [CUSTOMERS' INTERRUPTIONS CAUSED BY POWER 75.32 RESTORATION PROCESS.] "Customers' interruptions caused by power 75.33 restoration process" means when customers lose power as a result 75.34 of the process of restoring power. The duration of these 75.35 outages is included in the customer-minutes of interruption. 75.36 Only the customers affected by the power restoration outages 76.1 that were not affected by the original outage are added to the 76.2 number of customer interruptions. 76.3 Subd. 8. [CUSTOMER-MINUTES OF 76.4 INTERRUPTION.] "Customer-minutes of interruption" means the 76.5 number of minutes of forced outage duration multiplied by the 76.6 number of customers affected. 76.7 Subd. 9. [ELECTRIC DISTRIBUTION LINE.] "Electric 76.8 distribution line" means circuits operating at less than 40,000 76.9 volts. 76.10 Subd. 10. [FORCED OUTAGE.] "Forced outage" means an outage 76.11 that cannot be deferred. 76.12 Subd. 11. [MAJOR CATASTROPHIC EVENTS.] "Major catastrophic 76.13 events" means events that are beyond the utility's control that 76.14 result in widespread system damages causing customer 76.15 interruptions that affect at least ten percent of the customers 76.16 in the system or in an operating area or that result in 76.17 customers being without electric service for durations of at 76.18 least 24 hours. 76.19 Subd. 12. [MAJOR STORM.] "Major storm" means a period of 76.20 severe adverse weather resulting in widespread system damage 76.21 causing customer interruptions that affect at least ten percent 76.22 of the customers on the system or in an operating area or that 76.23 result in customers being without electric service for durations 76.24 of at least 24 hours. 76.25 Subd. 13. [MOMENTARY INTERRUPTION.] "Momentary 76.26 interruption" means an interruption of electric service with a 76.27 duration shorter than the time necessary to be classified as a 76.28 customer interruption. 76.29 Subd. 14. [OPERATING AREA.] "Operating area" means a 76.30 geographical subdivision of each electric utility's service 76.31 territory that functions under the direction of a company office 76.32 and may be used for reporting interruptions under this article. 76.33 These areas may also be referred to as regions, divisions, or 76.34 districts. 76.35 Subd. 15. [OUTAGE.] "Outage" means the failure of a power 76.36 system component that results in one or more customer 77.1 interruptions. 77.2 Subd. 16. [OUTAGE DURATION.] "Outage duration" means the 77.3 one minute or greater period from the initiation of an 77.4 interruption to a customer until service has been restored to 77.5 that customer. 77.6 Subd. 17. [PARTIAL CIRCUIT OUTAGE CUSTOMER 77.7 COUNT.] "Partial circuit outage customer count" means when only 77.8 part of a circuit experiences an outage, the number of customers 77.9 affected is estimated, unless an actual count is available. 77.10 When power is partially restored, the number of customers 77.11 restored is also estimated. Most utilities use estimates based 77.12 on the portion of the circuit restored. 77.13 Subd. 18. [PLANNED OUTAGES.] "Planned outages" means those 77.14 outages scheduled by the utility. These interruptions are 77.15 sometimes necessary to connect new customers or perform 77.16 maintenance activities safely. They must not be included in the 77.17 calculation of reliability indexes. 77.18 Subd. 19. [RELIABILITY.] "Reliability" means the degree to 77.19 which electric service is supplied without interruption. 77.20 Subd. 20. [RELIABILITY INDEXES.] "Reliability indexes" 77.21 include the following performance indices for measuring 77.22 frequency and duration of service interruptions: 77.23 (a) The system average interruption frequency index is the 77.24 average number of interruptions per customer per year. It is 77.25 determined by dividing the total annual number of customer 77.26 interruptions by the average number of customers served during 77.27 the year. 77.28 (b) The system average interruption duration index is the 77.29 average customer-minutes of interruption per customer. It is 77.30 determined by dividing the annual sum of customer-minutes of 77.31 interruption by the average number of customers served during 77.32 the year. 77.33 (c) The customer average interruption duration index is the 77.34 average customer-minutes of interruption per customer 77.35 interruption. It approximates the average length of time 77.36 required to complete service restoration. It is determined by 78.1 dividing the annual sum of all customer-minutes of interruption 78.2 durations by the annual number of customer interruptions. 78.3 Sec. 2. [216B.82] [RECORDING SERVICE INTERRUPTION 78.4 INDEXES.] 78.5 Subdivision 1. [SYSTEM INTERRUPTION DATA.] Each electric 78.6 utility with 10,000 retail customers or more shall keep a record 78.7 of the necessary interruption data and calculate the system 78.8 average interruption frequency index, system average 78.9 interruption duration index, and customer average interruption 78.10 duration index of its system, and of each operating area, if 78.11 applicable, at the end of each calendar year for the previous 78.12 12-month period. 78.13 Subd. 2. [CIRCUIT INTERRUPTION DATA.] Unless a utility 78.14 uses alternative criteria as provided in section 216B.83, 78.15 subdivision 2, paragraph (d), each utility also shall, at the 78.16 end of each calendar year, calculate the system average 78.17 interruption frequency index, system average interruption 78.18 duration index, and customer average interruption duration index 78.19 for each circuit in each operating area. Each circuit in each 78.20 operating area must then be listed in order separately according 78.21 to its system average interruption frequency index, its system 78.22 average interruption duration index, and its customer average 78.23 interruption duration index, beginning with the highest values 78.24 for each index. 78.25 Sec. 3. [216B.83] [ANNUAL REPORT.] 78.26 Subdivision 1. [SUMMARY REPORT GENERALLY.] Beginning on 78.27 July 1, 2002, and by July 1 of every year thereafter, each 78.28 electric utility with 10,000 retail customers or more shall file 78.29 with the commission, or in the case of a cooperative electric 78.30 association or municipal utility, with the local governing body 78.31 of the utility or association a report summarizing various 78.32 measures of reliability. The form of the report is subject to 78.33 review and comment by the commission staff. Names and numbers 78.34 used to identify operating areas or individual circuits may 78.35 conform to the utility's practice, but should allow ready 78.36 identification of the geographic location or the general area 79.1 served. Electronic recording and reporting of the required data 79.2 and information is encouraged. 79.3 Subd. 2. [INFORMATION REQUIRED.] (a) The report must 79.4 include at least the information described in paragraphs (b) to 79.5 (h). 79.6 (b) The report must provide an overall assessment of the 79.7 reliability of performance including the aggregate system 79.8 average interruption frequency index, system average 79.9 interruption duration index, and customer average interruption 79.10 duration index by system and each operating area, as applicable. 79.11 (c) The report must include a list of the worst performing 79.12 circuits based on system average interruption frequency index, 79.13 system average interruption duration index, and customer average 79.14 interruption duration index for the calendar year. This portion 79.15 of the report must describe the actions that the utility has 79.16 taken or will take to remedy the conditions responsible for each 79.17 listed circuit's unacceptable performance. The actions taken or 79.18 planned should be briefly described. Target dates for 79.19 corrective actions must be included in the report. When the 79.20 utility determines that actions on its part are unwarranted, its 79.21 report shall provide adequate justification for that conclusion. 79.22 (d) Utilities that use or prefer alternative criteria for 79.23 measuring individual circuit performance to those described in 79.24 paragraphs (b) and (c) and that are required by this section to 79.25 submit an annual report of reliability data, shall submit their 79.26 alternative listing of circuits along with the criteria used to 79.27 rank circuit performance. 79.28 (e) Information must be included with respect to any report 79.29 on the accomplishment of the improvements proposed in prior 79.30 reports for which completion has not been previously reported. 79.31 (f) The report must describe any new reliability or power 79.32 quality programs and changes that are made to existing programs. 79.33 (g) It must include a status report of any long-range 79.34 electric distribution plans. 79.35 (h) In addition to the information included in paragraph 79.36 (b), each utility that has the technical capability and 80.1 administrative resources shall report the following additional 80.2 service quality information: 80.3 (1) route miles of electric distribution line reconstructed 80.4 during the year, with separate totals for single- and 80.5 three-phase circuits provided; 80.6 (2) total route miles of electric distribution line in 80.7 service at year's end, segregated by voltage level; 80.8 (3) monthly average speed of answer for telephone calls 80.9 received regarding emergencies; 80.10 (4) the average number of calendar days a utility takes to 80.11 install and energize service to a customer site once it is ready 80.12 to receive service, with a separate average calculated for each 80.13 month, including all extensions energized during the calendar 80.14 month; 80.15 (5) the total number of written and telephone customer 80.16 complaints received in the areas of safety, outages, power 80.17 quality, customer property damage, and other areas, by month 80.18 filed; 80.19 (6) total annual tree-trimming budget and actual expenses; 80.20 and 80.21 (7) total annual projected and actual miles of tree-trimmed 80.22 distribution line. 80.23 Sec. 4. [216B.84] [INITIAL HISTORICAL RELIABILITY 80.24 PERFORMANCE REPORT.] 80.25 (a) Each electric utility with 10,000 retail customers or 80.26 more that has historically used measures of system, operating 80.27 area, and circuit reliability performance shall initially submit 80.28 annual system average interruption frequency index, system 80.29 average interruption duration index, and customer average 80.30 interruption duration index data for the previous three years. 80.31 Those utilities that have this data for some time period less 80.32 than three years shall submit data for those years it is 80.33 available. 80.34 (b) Those utilities whose historical reliability 80.35 performance data is similar or related to those measures listed 80.36 in paragraph (a), but differs due to how the parameters are 81.1 defined or calculated, shall submit the data it has and explain 81.2 any material differences from the prescribed indices. After the 81.3 effective date of this section, utilities shall modify their 81.4 reliability performance measures to conform to those specified 81.5 in sections 216B.81 to 216B.87 for purposes of consistent 81.6 reporting of comparable data in the future. 81.7 Sec. 5. [216B.85] [INTERRUPTIONS OF SERVICE; RECORDS; 81.8 NOTICE.] 81.9 Subdivision 1. [RECORDS.] (a) Each utility shall keep 81.10 records of all interruptions to service affecting the entire 81.11 distribution system of any single community or an important 81.12 division of a community, and include in the records each 81.13 interruption's location, date and time, and duration; the 81.14 approximate number of customers affected; the circuit or 81.15 circuits involved; and, when known, the cause of each 81.16 interruption. 81.17 (b) When complete distribution systems or portions of 81.18 communities have service furnished from unattended stations, 81.19 these records must be kept to the extent practicable. The 81.20 record of unattended stations shall show interruptions that 81.21 require attention to restore service, with the estimated time of 81.22 interruption. Breaker or fuse operations affecting service 81.23 should also be indicated even though duration of interruption 81.24 may not be known. 81.25 Subd. 2. [NOTICE OF INTERRUPTIONS OF BULK POWER SUPPLY 81.26 FACILITIES.] (a) Each utility owning or operating bulk power 81.27 supply facilities shall record any event described in clauses 81.28 (1) to (5) involving any generating unit or electric facilities 81.29 operating at a nominal voltage of 69 kilovolts or higher, and 81.30 shall make such records available to the commission semiannually 81.31 or upon request of the commission: 81.32 (1) any interruption or loss of service to customers for 15 81.33 minutes or more to aggregate firm loads in excess of 200,000 81.34 kilowatts; 81.35 (2) any interruption or loss of service to customers for 15 81.36 minutes or more to aggregate firm loads exceeding the lesser of 82.1 100,000 kilowatts or one-half of the current annual system peak 82.2 load and not required to be recorded under clause (1); 82.3 (3) any decision to issue a public request for reduction in 82.4 use of electricity; 82.5 (4) an action to reduce firm customer loads by reduction of 82.6 voltage for reasons of maintaining adequacy of bulk electric 82.7 power supply; and 82.8 (5) any action to reduce firm customer loads by manual 82.9 switching, operation of automatic load-shedding devices, or any 82.10 other means for reasons of maintaining adequacy of bulk electric 82.11 power supply. 82.12 Subd. 3. [NOTICE OF OTHER INTERRUPTIONS OF POWER.] Each 82.13 utility shall record service interruptions of 60 minutes or more 82.14 to an entire distribution substation bus or entire feeder 82.15 serving either 500 or more customers or entire cities or 82.16 villages having 200 or more customers. 82.17 Subd. 4. [INFORMATION REQUIRED.] The written records 82.18 required in subdivisions 2 and 3 must include the date, time, 82.19 duration, general location, approximate number of customers 82.20 affected, identification of circuit or circuits involved, and, 82.21 when known, the cause of the interruption. When extensive 82.22 interruptions occur, as from a storm, a narrative record 82.23 including the extent of the interruptions and system damage, 82.24 estimated number of customers affected, and a list of entire 82.25 communities interrupted may be recorded in lieu of records of 82.26 individual interruptions. When customer service interruptions 82.27 are necessary, the utility shall make reasonable efforts to 82.28 notify affected customers in advance. 82.29 Sec. 6. [216B.86] [CUSTOMERS' COMPLAINTS.] 82.30 Each utility shall keep a record of complaints received by 82.31 it from its customers in regard to safety or service, and the 82.32 operation of its system, with appropriate response times 82.33 designated for critical safety and monetary loss situations and 82.34 shall investigate if appropriate. The record must show the name 82.35 and address of the complainant, the date and nature of the 82.36 complaint, the priority assigned to the assistance, and its 83.1 disposition and the time and date of its disposition. 83.2 Sec. 7. [216B.87] [STANDARDS FOR DISTRIBUTION UTILITIES.] 83.3 (a) The commission and each cooperative electric 83.4 association and municipal utility shall, only as resources 83.5 allow, adopt standards for safety, reliability, and service 83.6 quality for distribution utilities. Standards for cooperative 83.7 electric associations and municipal utilities should be as 83.8 consistent as possible with the commission standards. 83.9 (b) Reliability standards must be based on the system 83.10 average interruption frequency index, system average 83.11 interruption duration index, and customer average interruption 83.12 duration index measurement indices. Service quality standards 83.13 must specify, if technically and administratively feasible: 83.14 (1) average call center response time; 83.15 (2) customer disconnection rate; 83.16 (3) meter-reading frequency; 83.17 (4) complaint resolution response time; and 83.18 (5) service extension request response time. 83.19 (c) Minimum performance standards developed under this 83.20 section must treat similarly situated distribution systems 83.21 similarly and recognize differing characteristics of system 83.22 design and hardware. 83.23 (d) Electric distribution utilities shall comply with all 83.24 applicable governmental and industry standards required for the 83.25 safety, design, construction, and operation of electric 83.26 distribution facilities, including section 326.243. 83.27 Sec. 8. [COST BENEFIT ANALYSIS.] 83.28 The commissioner of commerce shall provide an analysis of 83.29 the costs and benefits to consumers and utilities of the 83.30 provisions of sections 1 to 7, including any recommended changes 83.31 to those provisions, to the chairs of the house of 83.32 representatives and senate policy and finance committees with 83.33 jurisdiction over electric utility issues by February 1, 2002. 83.34 Sec. 9. [EFFECTIVE DATE.] 83.35 Sections 1 to 7 are effective July 1, 2003. Section 8 is 83.36 effective the day following final enactment.