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 reliability plan; 
  1.5             providing for essential energy infrastructure; 
  1.6             eliminating the requirement for individual utility 
  1.7             plans; creating an independent reliability 
  1.8             administrator; modifying provisions for siting, 
  1.9             routing, and determining the need for large electric 
  1.10            power facilities; regulating conservation expenditures 
  1.11            by energy utilities and eliminating state pre-approval 
  1.12            of conservation plans by public utilities; encouraging 
  1.13            regulatory flexibility in supplying and obtaining 
  1.14            energy; regulating interconnection of distributed 
  1.15            utility resources; providing for safety and service 
  1.16            standards from distribution utilities; clarifying the 
  1.17            state cold weather disconnection requirements; 
  1.18            authorizing municipal utilities, municipal power 
  1.19            agencies, cooperative utilities, and investor-owned 
  1.20            utilities to form joint ventures to provide utility 
  1.21            services; making technical, conforming, and clarifying 
  1.22            changes; amending Minnesota Statutes 2000, sections 
  1.23            116.07, subdivision 4a; 116C.52, subdivision 4; 
  1.24            116C.53, subdivision 3; 116C.57, subdivisions 1, 2, 4, 
  1.25            by adding subdivisions; 116C.58; 116C.59, subdivision 
  1.26            1; 116C.60; 116C.61, subdivision 1; 116C.62; 116C.64; 
  1.27            116C.645; 116C.65; 116C.66; 116C.69; 216A.03, 
  1.28            subdivision 3a; 216B.03; 216B.095; 216B.097, 
  1.29            subdivision 1; 216B.16, subdivisions 1, 6b, 6c, 7, 15, 
  1.30            by adding a subdivision; 216B.162, subdivision 8; 
  1.31            216B.1621, subdivision 2; 216B.164, subdivision 4; 
  1.32            216B.241, subdivisions 1, 1a, 1b, 2, by adding 
  1.33            subdivisions; 216B.2421, subdivision 2, by adding a 
  1.34            subdivision; 216B.2423, subdivision 2; 216B.243, 
  1.35            subdivisions 2, 3, 4, by adding a subdivision; 
  1.36            216C.17, subdivision 3; 216C.41; proposing coding for 
  1.37            new law in Minnesota Statutes, chapters 116C; 216B; 
  1.38            452; repealing Minnesota Statutes 2000, sections 
  1.39            116C.55; 116C.57, subdivisions 3, 5, 5a; 116C.67; 
  1.40            216B.241, subdivision 1c; 216B.2422, subdivisions 2, 
  1.41            6; 216C.18. 
  1.42  BE IT ENACTED BY THE LEGISLATURE OF THE STATE OF MINNESOTA: 
  1.43                             ARTICLE 1
  2.1                           ENERGY PLANNING
  2.2      Section 1.  [TITLE.] 
  2.3      This act shall be known as the Minnesota Energy Security 
  2.4   and Reliability Act. 
  2.5      Sec. 2.  [216B.011] [ADMINISTRATOR; ASSESSMENTS; 
  2.6   APPROPRIATION; REPORT.] 
  2.7      Subdivision 1.  [CREATION.] (a) Recognizing the critical 
  2.8   importance of adequate, reliable, and environmentally sound 
  2.9   energy services to the state's economy and the well-being of its 
  2.10  citizens, and that responsibility for reliability is dispersed 
  2.11  among several state agencies, the commissioner of commerce shall 
  2.12  appoint an independent reliability administrator within the 
  2.13  department of commerce.  
  2.14     (b) The commissioner, with the advice and consent of the 
  2.15  commission, shall appoint the administrator for a term 
  2.16  concurrent with that of the governor.  The administrator may be 
  2.17  removed only for cause.  In addition to appointing the 
  2.18  administrator, the commissioner shall oversee and direct the 
  2.19  work of the administrator, annually audit the expenses of the 
  2.20  administrator, and biennially approve the budget of the 
  2.21  administrator. 
  2.22     (c) The administrator may utilize staff from the 
  2.23  department, commission, and the board, at the discretion of the 
  2.24  administrative heads of those agencies; may hire staff; and may 
  2.25  contract for technical expertise in performing duties when 
  2.26  existing state resources are required for other state 
  2.27  responsibilities or when special expertise is required. 
  2.28     (d) The salary of the administrator is governed by section 
  2.29  15A.0815, subdivision 2. 
  2.30     Subd. 2.  [DUTIES.] (a) The administrator shall increase 
  2.31  state agency technical expertise and understanding of 
  2.32  reliability needs and increase public confidence in proposed 
  2.33  infrastructure projects by: 
  2.34     (1) modeling and monitoring the use and operation of the 
  2.35  energy infrastructure in the state, including generation 
  2.36  facilities, transmission lines, natural gas pipelines, and other 
  3.1   energy infrastructure; 
  3.2      (2) identifying weaknesses, constraints, and conditions 
  3.3   that, based on the utility's most recent forecast or consistent 
  3.4   with the transmission expansion plan of a federally approved 
  3.5   regional transmission organization or regional reliability 
  3.6   entity, may materially limit the adequacy of energy supply, 
  3.7   efficiency of energy service, or reliability of energy service 
  3.8   to consumers in Minnesota that may require construction of a 
  3.9   generation, transmission, or natural gas pipeline project; 
  3.10     (3) developing and consolidating technical analyses of 
  3.11  proposed infrastructure projects, to be utilized by the 
  3.12  commission, the department, the office of attorney general, the 
  3.13  environmental quality board, and the pollution control agency in 
  3.14  reviewing applications for infrastructure approvals under the 
  3.15  jurisdiction of those respective agencies; 
  3.16     (4) assessing, from a technical standpoint, assertions of 
  3.17  need for additional infrastructure for the members of the 
  3.18  regional energy infrastructure planning groups; 
  3.19     (5) developing, issuing, and presenting the reliability 
  3.20  status report required under subdivision 4 and the state 
  3.21  reliability plan under section 216B.012; 
  3.22     (6) hosting public meetings around the state to present 
  3.23  independent, factual, expert, technical information on 
  3.24  infrastructure proposals; and 
  3.25     (7) coordinating with regional energy infrastructure 
  3.26  planning groups; regulators and reliability officials of other 
  3.27  states; regional reliability entities; and the federal 
  3.28  government. 
  3.29     (b) The commission, department, and environmental quality 
  3.30  board shall refer applications for transmission infrastructure 
  3.31  approvals to the administrator for initial technical analysis of 
  3.32  the proposed infrastructure improvement on reliability of energy 
  3.33  services to Minnesota consumers.  The administrator shall 
  3.34  provide written and oral technical assistance on the application 
  3.35  to each referring agency, and shall provide such advice and 
  3.36  analysis as that agency deems necessary. 
  4.1      (c) The administrator shall certify its administrative 
  4.2   costs to the commission on a monthly basis, and shall specify 
  4.3   those costs that are general in nature, and those that were 
  4.4   incurred on a specific application or with regard to a specific 
  4.5   utility.  The commission shall review those costs, and shall 
  4.6   order payment within 30 days of commission review.  The 
  4.7   department shall render a bill to the utility or utilities, 
  4.8   either at the conclusion of the proceeding, analysis, or 
  4.9   service, or from time to time during the course of the 
  4.10  proceeding, analysis, or service.  The bill constitutes notice 
  4.11  of the assessment and a demand for payment.  The amount of the 
  4.12  bills so rendered by the department must be paid by the public 
  4.13  utility into the state treasury within 30 days from the date of 
  4.14  billing and are appropriated to the administrator for the 
  4.15  purposes provided in this section.  General administrative costs 
  4.16  of the administrator must not exceed $2,000,000 for a fiscal 
  4.17  biennium; however, additional amounts may be incurred and 
  4.18  recovered above this amount, if the commissioner and chair of 
  4.19  the commission deem the additional amounts to be necessary.  The 
  4.20  administrator shall provide a detailed accounting of its 
  4.21  finances to the commissioner and to the chairs of the house and 
  4.22  senate finance committees with jurisdiction over the 
  4.23  department's budget.  Costs that are of a general nature must be 
  4.24  apportioned among all energy utilities in proportion to their 
  4.25  respective gross operating revenues from retail sales of gas or 
  4.26  electric service within the state during the last calendar 
  4.27  year.  Within 30 days after the date of the mailing of any bill 
  4.28  as provided by this subdivision and subdivision 3, the utility 
  4.29  against which the bill has been rendered may file with the 
  4.30  commission objections setting out the grounds upon which it is 
  4.31  claimed the bill is excessive, erroneous, unlawful, or invalid.  
  4.32  Within 60 days, the commission shall hold a hearing and issue an 
  4.33  order in accordance with its findings.  The order is appealable 
  4.34  in the same manner as other final orders of the commission.  The 
  4.35  commission shall approve or approve as modified a rate schedule 
  4.36  providing for the automatic adjustment of charges to recover 
  5.1   amounts paid by utilities under this section. 
  5.2      Subd. 3.  [TECHNICAL ASSISTANCE.] Upon request, the 
  5.3   administrator shall provide technical assistance regarding 
  5.4   matters unrelated to applications for infrastructure 
  5.5   improvements to the department, the commission, and the board.  
  5.6      Subd. 4.  [RELIABILITY STATUS REPORT.] (a) The commission 
  5.7   shall require all distribution utilities, as technically and 
  5.8   administratively feasible, to report to the administrator on 
  5.9   operating and planning reserves, available transmission 
  5.10  capacity, outages of major generation units and feeders of 
  5.11  distribution and transmissions facilities, the adequacy of stock 
  5.12  and equipment, and any other information necessary to assess the 
  5.13  current and future reliability of energy service in this state.  
  5.14  Distribution utilities that are currently required to file 
  5.15  resource plans may submit updates, if applicable. 
  5.16     (b) The administrator shall, by January 1 of each 
  5.17  odd-numbered year beginning in 2003, assess and report to the 
  5.18  commissioner, with copies to the commission and the chairs of 
  5.19  the house and senate committees with jurisdiction over energy 
  5.20  policy issues, the status of the reliability of electric service 
  5.21  in the state and make recommendations, if applicable, for 
  5.22  regulatory or legislative action. 
  5.23     Sec. 3.  [216B.012] [STATE RELIABILITY PLAN.] 
  5.24     (a) By January 1 of every odd-numbered year, the 
  5.25  administrator shall develop and present to the commissioner 
  5.26  recommendations for a draft state reliability plan, consisting 
  5.27  of critical transmission system upgrades and new transmission 
  5.28  projects of 100 kilovolts or greater.  Only projects that, in 
  5.29  the opinion of the administrator, meet the criteria established 
  5.30  in section 216B.243 for issuing certificates of need and public 
  5.31  purpose designations for large energy facilities may be 
  5.32  recommended to be included in the administrator's 
  5.33  recommendations.  The plan may describe projects generally.  
  5.34  Specific locations and routes must be determined by the 
  5.35  environmental quality board as provided in section 116C.57 or 
  5.36  116C.575. 
  6.1      (b) In developing the administrator's recommendations, the 
  6.2   administrator shall consider: 
  6.3      (1) the most recent state energy security blueprint issued 
  6.4   under section 216B.015; 
  6.5      (2) the most recent regional energy infrastructure reports 
  6.6   issued by the regional energy infrastructure planning regions; 
  6.7      (3) any transmission plan issued by a federally approved 
  6.8   regional transmission organization for the region that includes 
  6.9   Minnesota, or issued by the reliability entity for this region 
  6.10  that is a member of the North American Electric Reliability 
  6.11  Council, or any successor organization; 
  6.12     (4) any deficiencies noticed under section 216B.019, 
  6.13  subdivision 5; 
  6.14     (5) any transmission plan developed and proposed jointly by 
  6.15  the transmission-owning or transmission-operating entities in 
  6.16  the state; 
  6.17     (6) the needs of transmission-dependent utilities and 
  6.18  customers in Minnesota; and 
  6.19     (7) any other information the administrator deems necessary 
  6.20  or reasonable.  
  6.21     (c) Each energy utility, energy service supplier, or 
  6.22  transmission owner or operator shall comply with all requests 
  6.23  for information that the administrator deems necessary to 
  6.24  complete the proposed plan. 
  6.25     (d) Within 30 days of receiving the administrator's 
  6.26  recommendations, the commissioner shall propose a draft state 
  6.27  reliability plan to the commission.  The commission shall 
  6.28  approve, reject, or approve as modified the plan proposed by the 
  6.29  commissioner within 180 days of issuance and shall publish the 
  6.30  plan in the State Register.  In making its decision under this 
  6.31  paragraph, the commission shall impose the criteria and 
  6.32  procedures established in section 216B.243 for issuing 
  6.33  certificates of need and public purpose designations.  Each 
  6.34  project in a state reliability plan approved by the commission 
  6.35  is exempt from additional commission review under section 
  6.36  216B.243. 
  7.1      (e) The administrator shall hold public meetings in all 
  7.2   areas of the state affected by the reliability plan.  
  7.3      (f) This chapter may not be construed to undermine the 
  7.4   existing and continuing obligation of the public utilities, 
  7.5   municipal utilities, and cooperative electric associations that 
  7.6   operate and provide service in this state to be ultimately 
  7.7   responsible for (1) providing reliable, affordable, safe, and 
  7.8   efficient energy services to their customers in this state, (2) 
  7.9   planning to meet the resource and infrastructure needs of those 
  7.10  customers, or (3) ensuring that those resources and 
  7.11  infrastructure are sited and constructed or otherwise acquired. 
  7.12     Sec. 4.  [216B.013] [EXISTING GENERATION FACILITIES.] 
  7.13     In order to continue the low-maintenance and low-cost 
  7.14  service that the existing base-load generation facilities in 
  7.15  Minnesota have provided to Minnesota consumers, and to provide 
  7.16  power to meet the growing demand for electricity by Minnesota 
  7.17  consumers and businesses, it is the policy of the state that 
  7.18  these facilities be maintained and upgraded consistent with 
  7.19  energy policy goals established pursuant to this chapter.  The 
  7.20  public utilities commission, department, and other state 
  7.21  agencies with regulatory jurisdiction over the operation of 
  7.22  these facilities shall take all steps necessary to incorporate 
  7.23  this state policy into the regulatory decisions made by each 
  7.24  respective agency. 
  7.25     Sec. 5.  [216B.014] [ENERGY SECURITY AND RELIABILITY.] 
  7.26     (a) It is a fundamental goal of Minnesota's energy and 
  7.27  utility policy that state policymakers maximize the state's 
  7.28  energy security.  
  7.29     (b) "Energy security" means, among other things, ensuring 
  7.30  that the state's energy sources are: 
  7.31     (1) diverse, including (i) traditional sources such as 
  7.32  coal, natural gas, waste-to-energy, and nuclear facilities, (ii) 
  7.33  renewable sources such as wind, biomass, and agricultural waste 
  7.34  generation, and (iii) high-efficiency, low-emissions distributed 
  7.35  generation sources such as fuel cells and microturbines; 
  7.36     (2) to the extent feasible, produced in the state utilizing 
  8.1   Minnesota's resources; 
  8.2      (3) environmentally sustainable; 
  8.3      (4) available to consumers at affordable and stable rates 
  8.4   or prices; and 
  8.5      (5) above all, reliable.  "Reliable" means, among other 
  8.6   things, that adequate resources and infrastructure are in place, 
  8.7   and are planned for, to provide efficient, dependable, and 
  8.8   secure energy services to Minnesota consumers.  
  8.9      Sec. 6.  [216B.015] [ENERGY SECURITY BLUEPRINT.] 
  8.10     (a) The commissioner shall develop a draft energy security 
  8.11  blueprint by March 1, 2002, and every four years thereafter.  
  8.12  The blueprint must: 
  8.13     (1) identify important trends and issues in energy supply, 
  8.14  consumption, conservation, and costs; 
  8.15     (2) set energy goals; and 
  8.16     (3) develop strategies to meet the goals. 
  8.17     (b) For the purposes of sections 216B.012 to 216B.019, the 
  8.18  terms:  
  8.19     (1) "electric utility" means an entity that is a public 
  8.20  utility; a cooperative electric association providing 
  8.21  generation, transmission, or distribution services; a municipal 
  8.22  utility; or a municipal power agency; and 
  8.23     (2) "energy utility" means an electric utility, or an 
  8.24  entity providing natural gas to retail consumers. 
  8.25     Sec. 7.  [216B.016] [ENERGY BLUEPRINT CONTENTS.] 
  8.26     The energy blueprint must include: 
  8.27     (1) the amount and type of projected statewide energy 
  8.28  consumption over the next ten years; 
  8.29     (2) a determination of whether and the extent to which 
  8.30  existing and anticipated energy production and transportation 
  8.31  facilities will or will not be able to supply needed energy; 
  8.32     (3) a determination of the potential for conservation to 
  8.33  meet some or all of the projected need for energy; 
  8.34     (4) an assessment of the environmental impact of projected 
  8.35  energy consumption over the next ten years, prepared by the 
  8.36  commissioner of the pollution control agency in consultation 
  9.1   with other state agencies and other interested persons, with 
  9.2   strategies to mitigate those impacts; and 
  9.3      (5) benchmarks to measure and monitor supply adequacy and 
  9.4   infrastructure capacity, and to assess the overall reliability 
  9.5   of the state's electric system. 
  9.6      Sec. 8.  [216B.017] [ENERGY GOALS.] 
  9.7      (a) The blueprint must recommend statewide goals and 
  9.8   recommend strategies to accomplish the following goals for: 
  9.9      (1) energy conservation and recovery; 
  9.10     (2) limiting adverse environmental emissions from the 
  9.11  generation of electric energy consumed in the state; 
  9.12     (3) production of electric energy consumed in the state 
  9.13  from renewable energy sources; 
  9.14     (4) deployment of distributed electric generation 
  9.15  technologies; 
  9.16     (5) ensuring that energy service is affordable and 
  9.17  available to all consumers in the state; 
  9.18     (6) minimizing the imposition of social costs on energy 
  9.19  consumers through energy rates or prices; and 
  9.20     (7) increasing the efficiency of the regulatory 
  9.21  infrastructure and reducing regulatory and administrative costs. 
  9.22     (b) The goals adopted in the blueprint may be one-time 
  9.23  goals or a series of goals to meet overall objectives.  The 
  9.24  commissioner shall present these goals, and any associated 
  9.25  strategies that require changes to state law, to the legislature 
  9.26  for modification and approval.  
  9.27     Sec. 9.  [216B.018] [BLUEPRINT DEVELOPMENT.] 
  9.28     Subdivision 1.  [PUBLIC PARTICIPATION.] The commissioner 
  9.29  shall: 
  9.30     (1) invite public and stakeholder comment and participation 
  9.31  during blueprint development; and 
  9.32     (2) hold at least one public meeting on the proposed 
  9.33  blueprint in each energy infrastructure planning region of the 
  9.34  state after at least 30 days' public notice in the region. 
  9.35     Subd. 2.  [NOTICE AND COMMENT; BLUEPRINT ISSUANCE.] The 
  9.36  commissioner shall provide notice of all public meetings to 
 10.1   discuss the proposed blueprint and allow opportunity for written 
 10.2   comment prior to issuing the final blueprint.  After review by 
 10.3   the administrator, the commissioner shall publish the final 
 10.4   energy blueprint in the State Register within four months of 
 10.5   issuing the draft blueprint. 
 10.6      Sec. 10.  [216B.019] [REGIONAL ENERGY INFRASTRUCTURE 
 10.7   PLANNING.] 
 10.8      Subdivision 1.  [ESTABLISHING PLANNING REGIONS.] The 
 10.9   commission, after notice and opportunity for written comment, 
 10.10  shall establish geographic regional energy infrastructure 
 10.11  planning regions in the state by August 1, 2001.  Planning 
 10.12  regions may coincide with existing subregional planning areas 
 10.13  used by the regional electric reliability or regional 
 10.14  transmission organization serving Minnesota.  The commission 
 10.15  shall also request comments on and approve, or approve as 
 10.16  modified, each group's organizational, administrative, planning, 
 10.17  and voting structures. 
 10.18     Subd. 2.  [PLANNING GROUP.] Each energy utility that 
 10.19  operates in an identified region shall participate in the 
 10.20  regional energy infrastructure planning group.  Each regional 
 10.21  group must include as voting members an equal number of 
 10.22  representatives of energy utilities, and representatives from 
 10.23  counties in the identified region, appointed by the county board.
 10.24     Subd. 3.  [PUBLIC MEETINGS.] Each regional energy 
 10.25  infrastructure planning group shall hold public meetings within 
 10.26  the region on a regular basis, not less than twice a year, and 
 10.27  provide public notice at least 14 calendar days in advance of a 
 10.28  meeting. 
 10.29     Subd. 4.  [REPORT.] By December 31, 2001, and every two 
 10.30  years thereafter, each regional energy infrastructure planning 
 10.31  group shall submit a report to the commissioner that: 
 10.32     (1) identifies inadequacies in electric generation and 
 10.33  transmission within the region including any deficiencies as 
 10.34  defined in subdivision 5; 
 10.35     (2) lists alternative ways to address identified 
 10.36  inadequacies, taking into account the provisions of the state 
 11.1   energy security blueprint; 
 11.2      (3) identifies potential general and, to the extent known, 
 11.3   specific economic, environmental, and social issues associated 
 11.4   with each alternative; and 
 11.5      (4) recommends alternatives to address identified 
 11.6   inadequacies and deficiencies that ensure the reliability and 
 11.7   security of the energy system in the region, while minimizing 
 11.8   environmental and social impacts.  In making recommendations, 
 11.9   the planning group shall identify critical needs.  For the 
 11.10  purposes of this clause, "critical needs" are those projects 
 11.11  that are necessary to maintain reliable electric service to 
 11.12  Minnesota consumers that meet or exceed the most stringent 
 11.13  applicable state or regional reliability standards.  A regional 
 11.14  planning group may satisfy the requirement to issue an initial 
 11.15  report under this section by submitting the portion of the 
 11.16  Mid-Continent Area Power Pool transmission plan that affects the 
 11.17  region, with any analysis, comment, or narrative that the group 
 11.18  deems important. 
 11.19     Subd. 5.  [DEFICIENCY.] (a) "Deficiency" means a condition, 
 11.20  or set of conditions, that, based on the utility's most recent 
 11.21  forecast or consistent with the transmission expansion plan of a 
 11.22  federally approved regional transmission organization or 
 11.23  regional reliability entity, may materially limit the adequacy 
 11.24  of electric supply, efficiency of electric service, or 
 11.25  reliability of electric service to an electric utility's 
 11.26  customers in the state that may require construction of a 
 11.27  generation or transmission project. 
 11.28     (b) Within 90 days of identifying a deficiency in its 
 11.29  system, an electric utility shall give notice of the deficiency 
 11.30  to at least: 
 11.31     (1) the members of affected regional energy infrastructure 
 11.32  planning groups; 
 11.33     (2) officials of potentially affected local governments; 
 11.34  and 
 11.35     (3) the commissioner and the independent reliability 
 11.36  administrator. 
 12.1      (c) Notice of deficiency must be made before submitting (1) 
 12.2   an application for a certificate of need under section 216B.243 
 12.3   or (2) a request for environmental review of an energy project 
 12.4   to any governmental entity.  
 12.5      Sec. 11.  [EFFECTIVE DATES.] 
 12.6      Sections 2 and 3 are effective July 1, 2002.  The rest of 
 12.7   this article is effective the day following final enactment. 
 12.8                              ARTICLE 2
 12.9                   ESSENTIAL ENERGY INFRASTRUCTURE
 12.10     Section 1.  Minnesota Statutes 2000, section 116.07, 
 12.11  subdivision 4a, is amended to read: 
 12.12     Subd. 4a.  [PERMITS.] (a) The pollution control agency may 
 12.13  issue, continue in effect, or deny permits, under such 
 12.14  conditions as it may prescribe for the prevention of pollution, 
 12.15  for (1) the emission of air contaminants except for emissions 
 12.16  from electric generation stations, or for (2) the installation 
 12.17  or operation of any emission facility, air contaminant treatment 
 12.18  facility, treatment facility, potential air contaminant storage 
 12.19  facility, or storage facility, or any part thereof, or for (3) 
 12.20  the sources or emissions of noise pollution. 
 12.21     The pollution control agency may also issue, continue in 
 12.22  effect or deny permits, under such conditions as it may 
 12.23  prescribe for the prevention of pollution, for, (4) the storage, 
 12.24  collection, transportation, processing, or disposal of waste, or 
 12.25  for (5) the installation or operation of any system or facility, 
 12.26  or any part thereof, related to the storage, collection, 
 12.27  transportation, processing, or disposal of waste.  The 
 12.28  commissioner, rather than the agency, may issue, continue in 
 12.29  effect, or deny permits, under conditions it may prescribe for 
 12.30  the prevention of pollution, for the emissions of air 
 12.31  contaminants from electric generation stations.  
 12.32  The pollution control agency may revoke or modify any permit 
 12.33  issued under this subdivision and section 116.081 whenever it is 
 12.34  necessary, in the opinion of the agency, to prevent or abate 
 12.35  pollution. 
 12.36     (b) The pollution control agency has the authority for 
 13.1   approval over the siting, expansion, or operation of a solid 
 13.2   waste facility with regard to environmental issues.  However, 
 13.3   the agency's issuance of a permit does not release the permittee 
 13.4   from any liability, penalty, or duty imposed by any applicable 
 13.5   county ordinances.  Nothing in this chapter precludes, or shall 
 13.6   be construed to preclude, a county from enforcing land use 
 13.7   controls, regulations, and ordinances existing at the time of 
 13.8   the permit application and adopted pursuant to sections 366.10 
 13.9   to 366.181, 394.21 to 394.37, or 462.351 to 462.365, with regard 
 13.10  to the siting, expansion, or operation of a solid waste facility.
 13.11     Sec. 2.  Minnesota Statutes 2000, section 116C.52, 
 13.12  subdivision 4, is amended to read: 
 13.13     Subd. 4.  [HIGH VOLTAGE TRANSMISSION LINE.] "High voltage 
 13.14  transmission line" means a conductor of electric energy and 
 13.15  associated facilities designed for and capable of operation at a 
 13.16  nominal voltage of 200 100 kilovolts or more, except that the 
 13.17  board, by rule, may exempt lines pursuant to section 116C.57, 
 13.18  subdivision 5. 
 13.19     Sec. 3.  Minnesota Statutes 2000, section 116C.53, 
 13.20  subdivision 3, is amended to read: 
 13.21     Subd. 3.  [INTERSTATE ROUTES.] (a) If a route is proposed 
 13.22  in two or more states, the board shall attempt to reach 
 13.23  agreement with affected states on the entry and exit points 
 13.24  prior to authorizing the construction of the route. The board, 
 13.25  in discharge of its duties pursuant to sections 116C.51 to 
 13.26  116C.69 may make joint investigations, hold joint hearings 
 13.27  within or without the state, and issue joint or concurrent 
 13.28  orders in conjunction or concurrence with any official or agency 
 13.29  of any state or of the United States.  The board may negotiate 
 13.30  and enter into any agreements or compacts with agencies of other 
 13.31  states, pursuant to any consent of Congress, for cooperative 
 13.32  efforts in certifying the construction, operation, and 
 13.33  maintenance of large electric power facilities in accord with 
 13.34  the purposes of sections 116C.51 to 116C.69 and for the 
 13.35  enforcement of the respective state laws regarding such these 
 13.36  facilities. 
 14.1      (b) The board may not issue a route permit for the 
 14.2   Minnesota portion of an interstate high voltage transmission 
 14.3   line unless the applicant has received a certificate of need 
 14.4   from the public utilities commission.  
 14.5      Sec. 4.  Minnesota Statutes 2000, section 116C.57, 
 14.6   subdivision 1, is amended to read: 
 14.7      Subdivision 1.  [DESIGNATION OF SITES SUITABLE FOR SPECIFIC 
 14.8   FACILITIES; REPORTS SITE PERMIT.] A utility must apply to the 
 14.9   board in a form and manner prescribed by the board for 
 14.10  designation of a specific site for a specific size and type of 
 14.11  facility.  The application shall contain at least two proposed 
 14.12  sites.  In the event a utility proposes a site not included in 
 14.13  the board's inventory of study areas, the utility shall specify 
 14.14  the reasons for the proposal and shall make an evaluation of the 
 14.15  proposed site based upon the planning policies, criteria and 
 14.16  standards specified in the inventory.  Pursuant to sections 
 14.17  116C.57 to 116C.60, the board shall study and evaluate any site 
 14.18  proposed by a utility and any other site the board deems 
 14.19  necessary which was proposed in a manner consistent with rules 
 14.20  adopted by the board concerning the form, content, and 
 14.21  timeliness of proposals for alternate sites.  No site 
 14.22  designation shall be made in violation of the site selection 
 14.23  standards established in section 116C.55.  The board shall 
 14.24  indicate the reasons for any refusal and indicate changes in 
 14.25  size or type of facility necessary to allow site designation. 
 14.26  Within a year after the board's acceptance of a utility's 
 14.27  application, the board shall decide in accordance with the 
 14.28  criteria specified in section 116C.55, subdivision 2, the 
 14.29  responsibilities, procedures and considerations specified in 
 14.30  section 116C.57, subdivision 4, and the considerations in 
 14.31  chapter 116D which proposed site is to be designated.  The board 
 14.32  may extend for just cause the time limitation for its decision 
 14.33  for a period not to exceed six months.  When the board 
 14.34  designates a site, it shall issue a certificate of site 
 14.35  compatibility to the utility with any appropriate conditions.  
 14.36  The board shall publish a notice of its decision in the State 
 15.1   Register within 30 days of site designation. No person may 
 15.2   construct a large electric power generating plant shall be 
 15.3   constructed except on without a site designated by permit from 
 15.4   the board or a county.  A large electric generating plant may be 
 15.5   constructed only on either (1) a site approved by the board 
 15.6   under this section or section 116C.575, or (2) a site designated 
 15.7   by a county using terms, conditions, procedures, and standards 
 15.8   no less stringent than those imposed and used by the board. 
 15.9      Sec. 5.  Minnesota Statutes 2000, section 116C.57, 
 15.10  subdivision 2, is amended to read: 
 15.11     Subd. 2.  [DESIGNATION OF ROUTES; PROCEDURE ROUTE PERMIT.] 
 15.12  A utility shall apply to the board in a form and manner 
 15.13  prescribed by the board for a permit for the construction of a 
 15.14  high voltage transmission line.  The application shall contain 
 15.15  at least two proposed routes.  Pursuant to sections 116C.57 to 
 15.16  116C.60, the board shall study, and evaluate the type, design, 
 15.17  routing, right-of-way preparation and facility construction of 
 15.18  any route proposed in a utility's application and any other 
 15.19  route the board deems necessary which was proposed in a manner 
 15.20  consistent with rules adopted by the board concerning the form, 
 15.21  content, and timeliness of proposals for alternate routes 
 15.22  provided, however, that the board shall identify the alternative 
 15.23  routes prior to the commencement of public hearings thereon 
 15.24  pursuant to section 116C.58.  Within one year after the board's 
 15.25  acceptance of a utility's application, the board shall decide in 
 15.26  accordance with the criteria and standards specified in section 
 15.27  116C.55, subdivision 2, and the considerations specified in 
 15.28  section 116C.57, subdivision 4, which proposed route is to be 
 15.29  designated.  The board may extend for just cause the time 
 15.30  limitation for its decision for a period not to exceed 90 days.  
 15.31  When the board designates a route, it shall issue a permit for 
 15.32  the construction of a high voltage transmission line specifying 
 15.33  the type, design, routing, right-of-way preparation and facility 
 15.34  construction it deems necessary and with any other appropriate 
 15.35  conditions.  The board may order the construction of high 
 15.36  voltage transmission line facilities which are capable of 
 16.1   expansion in transmission capacity through multiple circuiting 
 16.2   or design modifications.  The board shall publish a notice of 
 16.3   its decision in the state register within 30 days of issuance of 
 16.4   the permit.  (a) No person may construct a high voltage 
 16.5   transmission line shall be constructed except on without a route 
 16.6   designated by permit from the board or by a county pursuant to 
 16.7   paragraph (b), unless it was exempted pursuant to subdivision 
 16.8   5.  A high voltage transmission line may be constructed only 
 16.9   along a route approved by the board under this section or 
 16.10  section 116C.575, or by a county pursuant to paragraph (b). 
 16.11     (b) A high voltage transmission line of between 100 and 200 
 16.12  kilovolts may be permitted and routed by a county using terms, 
 16.13  conditions, procedures, and standards no less stringent than 
 16.14  those imposed and used by the board, unless the county requests 
 16.15  the board to route the proposed line. 
 16.16     Sec. 6.  Minnesota Statutes 2000, section 116C.57, is 
 16.17  amended by adding a subdivision to read: 
 16.18     Subd. 2a.  [APPLICATION.] (a) A person seeking to construct 
 16.19  a large electric power generating plant or a high voltage 
 16.20  transmission line shall apply to the board for a site permit or 
 16.21  route permit.  The application must contain any information 
 16.22  required by the board and must specify: 
 16.23     (1) whether the applicant is required to receive a 
 16.24  certificate of need for the proposed project; 
 16.25     (2) whether the applicant is required to comply with 
 16.26  section 216B.019, subdivision 5, and has complied; 
 16.27     (3) whether the proposed project was identified, discussed, 
 16.28  and considered by the relevant regional energy infrastructure 
 16.29  planning group and the result of that consideration. 
 16.30     (b) The applicant shall propose at least two sites for a 
 16.31  large electric power generating plant and two routes for a high 
 16.32  voltage transmission line. 
 16.33     (c) The chair of the board shall determine whether an 
 16.34  application is complete and advise the applicant of any 
 16.35  deficiencies. 
 16.36     Sec. 7.  Minnesota Statutes 2000, section 116C.57, is 
 17.1   amended by adding a subdivision to read: 
 17.2      Subd. 2b.  [NOTICE OF APPLICATION.] Within 15 days after 
 17.3   submitting an application to the board, the applicant shall 
 17.4   publish notice of the application in a legal newspaper of 
 17.5   general circulation in each county in which the site or route is 
 17.6   proposed and send a copy of the application by certified mail to 
 17.7   any regional development commission, county, incorporated 
 17.8   municipality, and town in which the site or route is proposed.  
 17.9   Within the same 15 days, the applicant shall also send a notice 
 17.10  of the submission of the application and description of the 
 17.11  proposed project to each owner whose property is adjacent to any 
 17.12  of the proposed sites for the power plant or along any of the 
 17.13  proposed routes for the transmission line.  The notice must 
 17.14  identify a location where a copy of the application can be 
 17.15  reviewed.  For the purpose of giving mailed notice under this 
 17.16  subdivision, owners are those shown on the records of the county 
 17.17  auditor or, in any county where tax statements are mailed by the 
 17.18  county treasurer, on the records of the county treasurer, but 
 17.19  other appropriate records may be used for this purpose.  The 
 17.20  failure to give mailed notice to a property owner, or defects in 
 17.21  the notice, does not invalidate the proceedings, provided a bona 
 17.22  fide attempt to comply with this subdivision has been made.  
 17.23  Within the same 15 days, the applicant shall also send the same 
 17.24  notice of the submission of the application and description of 
 17.25  the proposed project to those persons who have requested to be 
 17.26  placed on a list maintained by the board for receiving notice of 
 17.27  proposed large electric generating power plants and high voltage 
 17.28  transmission lines. 
 17.29     Sec. 8.  Minnesota Statutes 2000, section 116C.57, is 
 17.30  amended by adding a subdivision to read: 
 17.31     Subd. 2c.  [ENVIRONMENTAL REVIEW.] (a) After a complete 
 17.32  application has been submitted, an environmental impact 
 17.33  statement must be prepared by the board for each proposed large 
 17.34  electric generating plant and for each proposed high voltage 
 17.35  transmission line.  
 17.36     (b) The board shall not consider the no-build alternative 
 18.1   for any project that is required to have a certificate of need 
 18.2   from the public utilities commission.  
 18.3      (c) No other state environmental review documents are 
 18.4   required.  
 18.5      (d) The board shall study and evaluate any site or route 
 18.6   proposed by an applicant, in addition to any other site or route 
 18.7   the board deems necessary that was proposed in a manner 
 18.8   consistent with rules adopted by the board concerning the form, 
 18.9   content, and timeliness of proposals for alternate sites or 
 18.10  routes. 
 18.11     Sec. 9.  Minnesota Statutes 2000, section 116C.57, is 
 18.12  amended by adding a subdivision to read: 
 18.13     Subd. 2d.  [PUBLIC HEARING.] The board and the independent 
 18.14  reliability administrator shall hold a joint public hearing on 
 18.15  an application for a site permit for a large electric power 
 18.16  generating plant or a route permit for a high voltage 
 18.17  transmission line.  A hearing held for designating a site or 
 18.18  route must be conducted by an administrative law judge from the 
 18.19  office of administrative hearings under the contested case 
 18.20  procedures of chapter 14.  Notice of the hearing must be given 
 18.21  by the board at least ten days in advance but no earlier than 45 
 18.22  days prior to the commencement of the hearing.  Notice must be 
 18.23  by publication in a legal newspaper of general circulation in 
 18.24  the county in which the public hearing is to be held and by 
 18.25  certified mail to chief executives of the regional development 
 18.26  commissions, counties, organized towns, townships, and the 
 18.27  incorporated municipalities in which a site or route is 
 18.28  proposed.  A person may appear at the hearing and offer 
 18.29  testimony and exhibits without the necessity of intervening as a 
 18.30  formal party to the proceeding.  The administrative law judge 
 18.31  may allow a person to ask questions of other witnesses.  The 
 18.32  administrative law judge shall hold a portion of the hearing in 
 18.33  the area where the power plant or transmission line is proposed 
 18.34  to be located. 
 18.35     Sec. 10.  Minnesota Statutes 2000, section 116C.57, 
 18.36  subdivision 4, is amended to read: 
 19.1      Subd. 4.  [CONSIDERATIONS IN DESIGNATING SITES AND 
 19.2   ROUTES.] (a) To facilitate the study, research, evaluation, and 
 19.3   designation of sites and routes, the board shall be guided by, 
 19.4   but not limited to, the following responsibilities, procedures, 
 19.5   and considerations: 
 19.6      (1) evaluation of research and investigations relating to 
 19.7   the effects on land, water, and air resources of large electric 
 19.8   power generating plants and high voltage transmission line 
 19.9   routes and the effects of water and air discharges and electric 
 19.10  fields resulting from such facilities on public health and 
 19.11  welfare, vegetation, animals, materials, and aesthetic values, 
 19.12  including base line studies, predictive modeling, and monitoring 
 19.13  of the water and air mass at proposed and operating sites and 
 19.14  routes, evaluation of new or improved methods for minimizing 
 19.15  adverse impacts of water and air discharges and other matters 
 19.16  pertaining to the effects of power plants on the water and air 
 19.17  environment; 
 19.18     (2) environmental evaluation of sites and routes proposed 
 19.19  for future development and expansion and their relationship to 
 19.20  the land, water, air, and human resources of the state; 
 19.21     (3) evaluation of the effects of new electric power 
 19.22  generation and transmission technologies and systems related to 
 19.23  power plants designed to minimize adverse environmental effects; 
 19.24     (4) evaluation of the potential for beneficial uses of 
 19.25  waste energy from proposed large electric power generating 
 19.26  plants; 
 19.27     (5) analysis of the direct and indirect economic impact of 
 19.28  proposed sites and routes including, but not limited to, 
 19.29  productive agricultural land lost or impaired; 
 19.30     (6) evaluation of adverse direct and indirect environmental 
 19.31  effects which that cannot be avoided should the proposed site 
 19.32  and route be accepted; 
 19.33     (7) evaluation of alternatives to the applicant's proposed 
 19.34  site or route proposed pursuant to subdivisions 1 and 2; 
 19.35     (8) evaluation of potential routes which that would use or 
 19.36  parallel existing railroad and highway rights-of-way; 
 20.1      (9) evaluation of governmental survey lines and other 
 20.2   natural division lines of agricultural land so as to minimize 
 20.3   interference with agricultural operations; 
 20.4      (10) evaluation of the future needs for additional high 
 20.5   voltage transmission lines in the same general area as any 
 20.6   proposed route, and the advisability of ordering the 
 20.7   construction of structures capable of expansion in transmission 
 20.8   capacity through multiple circuiting or design modifications; 
 20.9      (11) evaluation of irreversible and irretrievable 
 20.10  commitments of resources should the proposed site or route be 
 20.11  approved; and 
 20.12     (12) where when appropriate, consideration of problems 
 20.13  raised by other state and federal agencies and local entities. 
 20.14     (13) (b) If the board's rules are substantially similar to 
 20.15  existing rules and regulations of a federal agency to which the 
 20.16  utility in the state is subject, the federal rules and 
 20.17  regulations shall must be applied by the board. 
 20.18     (14) (c) No site or route shall may be designated which 
 20.19  violates if to do so would violate state agency rules. 
 20.20     Sec. 11.  Minnesota Statutes 2000, section 116C.57, is 
 20.21  amended by adding a subdivision to read: 
 20.22     Subd. 7.  [TIMING.] The board shall make a final decision 
 20.23  on an application within 60 days after receipt of the report of 
 20.24  the administrative law judge.  A final decision on the request 
 20.25  for a site permit or route permit shall be made within one year 
 20.26  after the chair's determination that an application is 
 20.27  complete.  The time for the final decision may be extended for 
 20.28  up to 90 days for good cause and if all parties agree. 
 20.29     Sec. 12.  Minnesota Statutes 2000, section 116C.57, is 
 20.30  amended by adding a subdivision to read: 
 20.31     Subd. 8.  [FINAL DECISION.] (a) A site permit may not be 
 20.32  issued in violation of the site selection standards and criteria 
 20.33  established in this section and in rules adopted by the board.  
 20.34  The board shall indicate the reasons for any refusal and 
 20.35  indicate changes in size or type of facility necessary to allow 
 20.36  site designation.  When the board designates a site, it shall 
 21.1   issue a site permit to the applicant with any appropriate 
 21.2   conditions.  The board shall publish a notice of its decision in 
 21.3   the State Register within 30 days of issuing the site permit. 
 21.4      (b) A route permit may not be issued in violation of the 
 21.5   route selection standards and criteria established in this 
 21.6   section and in rules adopted by the board.  When the route is 
 21.7   designated, the permit issued for the construction of the 
 21.8   facility must specify the type, design, routing, right-of-way 
 21.9   preparation, and facility construction deemed necessary and any 
 21.10  other appropriate conditions.  The board may order the 
 21.11  construction of high voltage transmission line facilities that 
 21.12  are capable of expansion in transmission capacity through 
 21.13  multiple circuiting or design modifications.  The board shall 
 21.14  publish a notice of its decision in the State Register within 30 
 21.15  days of issuing the permit. 
 21.16     Sec. 13.  [116C.575] [ALTERNATIVE REVIEW OF APPLICATIONS.] 
 21.17     Subdivision 1.  [ALTERNATIVE REVIEW.] An applicant who 
 21.18  seeks a site permit or route permit for one of the projects 
 21.19  identified in this section may petition the board to be allowed 
 21.20  to follow the procedures in this section rather than the 
 21.21  procedures in section 116C.57.  The board shall grant the 
 21.22  petition within 30 days unless the board finds good cause for 
 21.23  denial.  
 21.24     Subd. 2.  [APPLICABLE PROJECTS.] The requirements and 
 21.25  procedures in this section may apply to the following projects: 
 21.26     (1) large electric power generating plants with a capacity 
 21.27  of between 50 and 80 megawatts regardless of fuel; 
 21.28     (2) large electric power generating plants powered by 
 21.29  natural gas as its primary fuel; 
 21.30     (3) projects to retrofit or repower an existing large 
 21.31  electric power generating plant to one burning primarily natural 
 21.32  gas or other similar clean fuel; 
 21.33     (4) any natural gas peaking facility designed for or 
 21.34  capable of storing on a single site more than 100,000 gallons of 
 21.35  liquefied natural gas or synthetic gas; 
 21.36     (5) high voltage transmission lines of between 100 and 200 
 22.1   kilovolts; 
 22.2      (6) high voltage transmission lines in excess of 200 
 22.3   kilovolts less than five miles in length in Minnesota; and 
 22.4      (7) high voltage transmission lines in excess of 200 
 22.5   kilovolts if at least 80 percent of the distance of the line in 
 22.6   Minnesota will be located along existing high voltage 
 22.7   transmission line right-of-way. 
 22.8      Subd. 3.  [APPLICATION.] The applicant for a site 
 22.9   certificate or route permit for any of the projects listed in 
 22.10  subdivision 2 who chooses to follow these procedures shall 
 22.11  submit information the board may require, but the applicant is 
 22.12  not required to propose a second site or route for the project.  
 22.13  The applicant shall identify in the application any other sites 
 22.14  or routes that were rejected by the applicant and the board may 
 22.15  identify additional sites or routes to consider during the 
 22.16  processing of the application.  The chair of the board shall 
 22.17  determine whether an application is complete and advise the 
 22.18  applicant of any deficiencies. 
 22.19     Subd. 4.  [NOTICE OF APPLICATION.] On submitting an 
 22.20  application under this section, the applicant shall provide the 
 22.21  same notice as required by section 116C.57, subdivision 4. 
 22.22     Subd. 5.  [ENVIRONMENTAL REVIEW.] For the projects 
 22.23  identified in subdivision 2 and following these procedures, the 
 22.24  board shall prepare an environmental assessment worksheet.  The 
 22.25  board shall include as part of the environmental assessment 
 22.26  worksheet alternative sites or routes identified by the board 
 22.27  and shall address mitigating measures for all of the sites or 
 22.28  routes considered.  The environmental assessment worksheet is 
 22.29  the only state environmental review document required to be 
 22.30  prepared on the project. 
 22.31     Subd. 6.  [PUBLIC MEETING.] The board and the independent 
 22.32  reliability administrator shall hold a joint public meeting in 
 22.33  the area where the facility is proposed to be located.  The 
 22.34  board shall give notice of the public meeting in the same manner 
 22.35  as notice for a public hearing.  The board shall provide 
 22.36  opportunity at the public meeting for any person to present 
 23.1   comments and to ask questions of the applicant and board staff.  
 23.2   The board shall also afford interested persons an opportunity to 
 23.3   submit written comments into the record. 
 23.4      Subd. 7.  [TIMING.] The board shall make a final decision 
 23.5   on an application within 60 days after completion of the public 
 23.6   meeting.  A final decision on the request for a site permit or 
 23.7   route permit under this section must be made within six months 
 23.8   after the chair's determination that an application is 
 23.9   complete.  The time for the final decision may be extended for 
 23.10  up to 45 days for good cause and if all parties agree. 
 23.11     Subd. 8.  [CONSIDERATIONS.] The considerations in section 
 23.12  116C.57, subdivision 4, apply to any projects subject to this 
 23.13  section. 
 23.14     Subd. 9.  [FINAL DECISION.] (a) A site permit may not be 
 23.15  issued in violation of the site selection standards and criteria 
 23.16  established in this section and in rules adopted by the board.  
 23.17  The board shall indicate the reasons for any refusal and 
 23.18  indicate changes in size or type of facility necessary to allow 
 23.19  site designation.  When the board designates a site, it shall 
 23.20  issue a site permit to the applicant with any appropriate 
 23.21  conditions.  The board shall publish a notice of its decision in 
 23.22  the State Register within 30 days of issuance of the site permit.
 23.23     (b) A route designation may not be made in violation of the 
 23.24  route selection standards and criteria established in this 
 23.25  section and in rules adopted by the board.  When the board 
 23.26  designates a route, it shall issue a permit for the construction 
 23.27  of a high voltage transmission line specifying the type, design, 
 23.28  routing, right-of-way preparation, and facility construction it 
 23.29  deems necessary and with any other appropriate conditions.  The 
 23.30  board may order the construction of high voltage transmission 
 23.31  line facilities that are capable of expansion in transmission 
 23.32  capacity through multiple circuiting or design modifications.  
 23.33  The board shall publish a notice of its decision in the State 
 23.34  Register within 30 days of issuance of the permit. 
 23.35     Sec. 14.  [116C.576] [EMERGENCY PERMIT.] 
 23.36     (a) Any utility whose electric power system requires the 
 24.1   immediate construction of a large electric power generating 
 24.2   plant or high voltage transmission line due to a major 
 24.3   unforeseen event may apply to the board for an emergency permit 
 24.4   after providing notice in writing to the public utilities 
 24.5   commission of the major unforeseen event and the need for 
 24.6   immediate construction.  The permit must be issued in a timely 
 24.7   manner, no later than 195 days after the board's acceptance of 
 24.8   the application and upon a finding by the board that (1) a 
 24.9   demonstrable emergency exists, (2) the emergency requires 
 24.10  immediate construction, and (3) adherence to the procedures and 
 24.11  time schedules specified in section 116C.57 would jeopardize the 
 24.12  utility's electric power system or would jeopardize the 
 24.13  utility's ability to meet the electric needs of its customers in 
 24.14  an orderly and timely manner. 
 24.15     (b) A public hearing to determine if an emergency exists 
 24.16  must be held within 90 days of the application.  The board, 
 24.17  after notice and hearing, shall adopt rules specifying the 
 24.18  criteria for emergency certification.  
 24.19     Sec. 15.  Minnesota Statutes 2000, section 116C.58, is 
 24.20  amended to read: 
 24.21     116C.58 [PUBLIC HEARINGS; NOTICE ANNUAL HEARING.] 
 24.22     The board shall hold an annual public hearing at a time and 
 24.23  place prescribed by rule in order to afford interested persons 
 24.24  an opportunity to be heard regarding its inventory of study 
 24.25  areas and any other aspects of the board's activities and duties 
 24.26  or policies specified in sections 116C.51 to 116C.69.  The board 
 24.27  shall hold at least one public hearing in each county where a 
 24.28  site or route is being considered for designation pursuant to 
 24.29  section 116C.57.  Notice and agenda of public hearings and 
 24.30  public meetings of the board held in each county shall be given 
 24.31  by the board at least ten days in advance but no earlier than 45 
 24.32  days prior to such hearings or meetings.  Notice shall be by 
 24.33  publication in a legal newspaper of general circulation in the 
 24.34  county in which the public hearing or public meeting is to be 
 24.35  held and by certified mailed notice to chief executives of the 
 24.36  regional development commissions, counties, organized towns and 
 25.1   the incorporated municipalities in which a site or route is 
 25.2   proposed.  All hearings held for designating a site or route or 
 25.3   for exempting a route shall be conducted by an administrative 
 25.4   law judge from the office of administrative hearings pursuant to 
 25.5   the contested case procedures of chapter 14.  Any person may 
 25.6   appear at the hearings and present testimony and exhibits and 
 25.7   may question witnesses without the necessity of intervening as a 
 25.8   formal party to the proceedings. any matters relating to the 
 25.9   siting of large electric generating power plants and routing of 
 25.10  high voltage transmission lines.  At the meeting, the board 
 25.11  shall advise the public of the permits issued by the board in 
 25.12  the past year.  The board shall provide at least ten days' 
 25.13  notice, but no more than 45 days' notice, of the annual meeting 
 25.14  by mailing notice to those persons who have requested notice and 
 25.15  by publication in the board's "EQB Monitor." 
 25.16     Sec. 16.  Minnesota Statutes 2000, section 116C.59, 
 25.17  subdivision 1, is amended to read: 
 25.18     Subdivision 1.  [ADVISORY TASK FORCE LOCAL PLANNING 
 25.19  COMMISSIONS.] The board may appoint one or more advisory task 
 25.20  forces shall confer with affected local planning commissions to 
 25.21  assist it in carrying out its duties.  Task forces appointed to 
 25.22  evaluate sites or routes considered for designation shall be 
 25.23  comprised of as many persons as may be designated by the board, 
 25.24  but at least one representative from each of the following:  
 25.25  Regional development commissions, counties and municipal 
 25.26  corporations and one town board member from each county in which 
 25.27  a site or route is proposed to be located.  No officer, agent, 
 25.28  or employee of a utility shall serve on an advisory task force.  
 25.29  Reimbursement for expenses incurred shall be made pursuant to 
 25.30  the rules governing state employees.  The task forces expire as 
 25.31  provided in section 15.059, subdivision 6. 
 25.32     Sec. 17.  Minnesota Statutes 2000, section 116C.60, is 
 25.33  amended to read: 
 25.34     116C.60 [PUBLIC MEETINGS; TRANSCRIPT OF PROCEEDINGS; 
 25.35  WRITTEN RECORDS.] 
 25.36     Meetings of the board, including hearings, shall must be 
 26.1   open to the public.  Minutes shall must be kept of board 
 26.2   meetings and a complete record of public hearings shall be 
 26.3   kept.  All books, records, files, and correspondence of the 
 26.4   board shall must be available for public inspection at any 
 26.5   reasonable time.  The council shall board is also be subject to 
 26.6   chapter 13D. 
 26.7      Sec. 18.  Minnesota Statutes 2000, section 216B.16, is 
 26.8   amended by adding a subdivision to read: 
 26.9      Subd. 17.  [DISTRIBUTED GENERATION TARIFF.] (a) In order to 
 26.10  facilitate and encourage the use of distributed generation, each 
 26.11  public utility providing electric service at retail shall file a 
 26.12  distributed generation tariff for commission approval or 
 26.13  approval with modification.  
 26.14     (b) The commission may, for distributed generation 
 26.15  facilities of no more than ten megawatts of interconnected 
 26.16  capacity, approve a tariff that it finds: 
 26.17     (1) provides for the low-cost, safe, and standardized 
 26.18  interconnection, consistent with sections 216B.68 to 216B.75, of 
 26.19  facilities fueled by natural gas or a renewable fuel, or another 
 26.20  similarly clean fuel or combination of fuels, and such 
 26.21  facilities may include, but are not limited to, fuel cells, 
 26.22  microturbines, wind turbines, or solar modules; 
 26.23     (2) encourages and compensates for the addition of 
 26.24  distributed generation power resources while reducing the cost 
 26.25  to the utility's customers for energy, capacity, transmission 
 26.26  and distribution; 
 26.27     (3) minimizes and avoids tariff-related increases in the 
 26.28  rates of customers not taking service under the distributed 
 26.29  generation tariff; and 
 26.30     (4) allows for reasonable terms and conditions, consistent 
 26.31  with the cost and operating characteristics of the various 
 26.32  technologies, so that the utility can be assured of the 
 26.33  reliable, safe, and efficient operation of the interconnected 
 26.34  equipment.  
 26.35     (c) The commission may develop financial incentives based 
 26.36  on a utility's performance in encouraging residential and small 
 27.1   business customers to participate in on-site generation. 
 27.2      Sec. 19.  Minnesota Statutes 2000, section 216B.2421, 
 27.3   subdivision 2, is amended to read: 
 27.4      Subd. 2.  [LARGE ENERGY FACILITY.] "Large energy facility" 
 27.5   means: 
 27.6      (1) any electric power generating plant or combination of 
 27.7   plants at a single site with a combined capacity of 80,000 
 27.8   kilowatts or more, or any facility of 50,000 kilowatts or more 
 27.9   which requires oil, natural gas, or natural gas liquids as a 
 27.10  fuel and for which an installation permit has not been applied 
 27.11  for by May 19, 1977 pursuant to Minn. Reg. APC 3(a); 
 27.12     (2) any high voltage transmission line with a capacity of 
 27.13  200 100 kilovolts or more and (i) with more than 50 ten miles 
 27.14  of its length in Minnesota, or (ii) any of its length in 
 27.15  Minnesota and that crosses the state line; or, any high voltage 
 27.16  transmission line with a capacity of 300 kilovolts or more with 
 27.17  more than 25 miles of its length in Minnesota; 
 27.18     (3) any pipeline greater than six inches in diameter and 
 27.19  having more than 50 miles of its length in Minnesota used for 
 27.20  the transportation of coal, crude petroleum or petroleum fuels 
 27.21  or oil or their derivatives; 
 27.22     (4) any pipeline for transporting natural or synthetic gas 
 27.23  at pressures in excess of 200 pounds per square inch with more 
 27.24  than 50 miles of its length in Minnesota; 
 27.25     (5) any facility designed for or capable of storing on a 
 27.26  single site more than 100,000 gallons of liquefied natural gas 
 27.27  or synthetic gas; 
 27.28     (6) any underground gas storage facility requiring permit 
 27.29  pursuant to section 103I.681; 
 27.30     (7) any nuclear fuel processing or nuclear waste storage or 
 27.31  disposal facility; and 
 27.32     (8) any facility intended to convert any material into any 
 27.33  other combustible fuel and having the capacity to process in 
 27.34  excess of 75 tons of the material per hour. 
 27.35     Sec. 20.  Minnesota Statutes 2000, section 216B.2421, is 
 27.36  amended by adding a subdivision to read: 
 28.1      Subd. 4.  [MODIFYING EXISTING LARGE ENERGY FACILITY.] 
 28.2   Refurbishing or upgrading an existing large energy facility 
 28.3   through the replacement or addition of facility components does 
 28.4   not require a certificate of need under section 216B.243, unless 
 28.5   the changes lead to (1) a capacity increase of more than 100 
 28.6   megawatts, or ten percent of existing capacity, whichever is 
 28.7   greater, or (2) operation at more than 50 percent higher voltage.
 28.8      Sec. 21.  Minnesota Statutes 2000, section 216B.243, 
 28.9   subdivision 2, is amended to read: 
 28.10     Subd. 2.  [CERTIFICATE REQUIRED.] (a) Except as provided in 
 28.11  paragraph (b), no large energy facility shall may be sited or 
 28.12  constructed in Minnesota without the issuance of a certificate 
 28.13  of need by the commission pursuant to sections 216C.05 to 
 28.14  216C.30 and this section and consistent with the criteria for 
 28.15  assessment of need. 
 28.16     (b) Notwithstanding paragraph (a), a large energy facility 
 28.17  that is a generation facility of 500 megawatts or less or a 
 28.18  natural gas peaking facility not owned by a public or municipal 
 28.19  utility or cooperative electric association and that is not to 
 28.20  be included in the utility's or association's rate base does not 
 28.21  need a certificate of need under this section. 
 28.22     (c) The commission may not issue a certificate of need for 
 28.23  a generation facility with coal as its primary fuel, unless the 
 28.24  commission finds that the facility implements the most stringent 
 28.25  technology and processes technically achievable, to ensure the 
 28.26  least impact on the state's environment from the facility. 
 28.27     Sec. 22.  Minnesota Statutes 2000, section 216B.243, is 
 28.28  amended by adding a subdivision to read: 
 28.29     Subd. 2a.  [PUBLIC PURPOSE DESIGNATION.] (a) When filing 
 28.30  for a certificate of need under this section, an applicant may 
 28.31  also petition the commission to designate the proposed large 
 28.32  energy facility a public purpose project.  The commission shall 
 28.33  approve or reject the petition at the same time the commission 
 28.34  renders its decision under subdivision 5.  Notwithstanding 
 28.35  section 116C.63 or any other law to the contrary, eminent domain 
 28.36  authority may not be used in constructing a large energy 
 29.1   facility unless the commission designates the facility a public 
 29.2   purpose project.  The value paid for property in the exercise of 
 29.3   eminent domain authority may be structured so as to provide for 
 29.4   the payment of a portion of the revenue derived from the large 
 29.5   energy facility over a period of years, rather than a lump sum 
 29.6   payment at the time the property is taken. 
 29.7      (b) In deciding whether to designate a proposed large 
 29.8   energy facility as a public purpose project, the commission 
 29.9   shall consider whether the proposed facility: 
 29.10     (1) remedies a condition, or set of conditions, that, based 
 29.11  on the utility's most recent forecast or consistent with the 
 29.12  transmission expansion plan of a federally approved regional 
 29.13  transmission organization or regional reliability entity, may 
 29.14  materially limit the adequacy of electric supply, efficiency of 
 29.15  electric service, or reliability of electric service to 
 29.16  Minnesota consumers; 
 29.17     (2) was identified as a critical need by the relevant 
 29.18  regional energy infrastructure planning group; 
 29.19     (3) is consistent with all relevant state goals and 
 29.20  strategies approved by the legislature under section 216B.017; 
 29.21  and 
 29.22     (4) is otherwise in the public interest. 
 29.23     Sec. 23.  Minnesota Statutes 2000, section 216B.243, 
 29.24  subdivision 3, is amended to read: 
 29.25     Subd. 3.  [SHOWING REQUIRED FOR CONSTRUCTION.] No (a) A 
 29.26  proposed large energy facility shall may not be certified for 
 29.27  construction unless the applicant can show that demand for 
 29.28  electricity cannot be met more cost-effectively through energy 
 29.29  conservation and load-management measures and unless the 
 29.30  applicant has otherwise justified its need.  
 29.31     (b) In assessing need, the commission shall evaluate: 
 29.32     (1) the accuracy of the long-range energy demand forecasts 
 29.33  on which the necessity for the facility is based; 
 29.34     (2) the effect of existing or possible energy conservation 
 29.35  programs under sections 216C.05 to 216C.30 and this section or 
 29.36  other federal or state legislation on long-term energy demand; 
 30.1      (3) the relationship of the proposed facility to overall 
 30.2   state and regional energy needs, as described in the most recent 
 30.3   state energy policy and conservation report prepared under 
 30.4   section 216C.18 including consideration of (i) the most recent 
 30.5   state energy security blueprint under section 216B.015, (ii) the 
 30.6   most recent relevant regional energy infrastructure planning 
 30.7   group report under section 216B.019, and (iii) information from 
 30.8   federal and regional reliability organizations, regional 
 30.9   transmission organizations, and other relevant sources; 
 30.10     (4) promotional activities that may have given rise to the 
 30.11  demand for this facility; 
 30.12     (5) socially beneficial uses of the output (3) 
 30.13  environmental and socioeconomic benefits of this facility, 
 30.14  including its uses to protect or enhance environmental quality, 
 30.15  to increase reliability of energy supply in Minnesota and the 
 30.16  region, and to induce future development; 
 30.17     (6) the effects of the facility in inducing future 
 30.18  development; 
 30.19     (7) (4) possible alternatives for satisfying the energy 
 30.20  demand or transmission needs including but not limited to 
 30.21  potential for increased efficiency and upgrading of existing 
 30.22  energy generation and transmission facilities, load management 
 30.23  programs, and distributed generation; 
 30.24     (8) (5) the policies, rules, and regulations of other state 
 30.25  and federal agencies and local governments; and 
 30.26     (9) any (6) feasible combination of energy conservation 
 30.27  improvements, required under section 216B.241, sections 216C.05 
 30.28  to 216C.30, or other available conservation programs that can (i)
 30.29  reasonably replace a significant part or all of the energy to be 
 30.30  provided by the proposed facility, and (ii) compete with it 
 30.31  economically and in terms of reliability; and 
 30.32     (7) whether the proposed large energy facility was 
 30.33  recommended for construction by the relevant regional energy 
 30.34  infrastructure planning group. 
 30.35     Sec. 24.  Minnesota Statutes 2000, section 216B.243, 
 30.36  subdivision 4, is amended to read: 
 31.1      Subd. 4.  [APPLICATION FOR CERTIFICATE; HEARING.] Any 
 31.2   person proposing to construct a large energy facility shall 
 31.3   apply for a certificate of need prior to construction of the 
 31.4   facility.  The application shall be on forms and in a manner 
 31.5   established by the commission.  In reviewing each application 
 31.6   the commission shall hold at least one public hearing pursuant 
 31.7   to chapter 14.  The public hearing shall be held at a location 
 31.8   and hour reasonably calculated to be convenient for the public.  
 31.9   An objective of the public hearing shall be to obtain public 
 31.10  opinion on the necessity of granting a certificate of need.  The 
 31.11  commission shall designate a commission employee whose duty 
 31.12  shall be to facilitate citizen participation in the hearing 
 31.13  process.  If the commission and the environmental quality board 
 31.14  determine that a joint hearing on siting and need under this 
 31.15  subdivision and section 116C.57, subdivision 2d, is feasible, 
 31.16  more efficient, and may further the public interest, a joint 
 31.17  hearing under those subdivisions may be held. 
 31.18     Sec. 25.  [INSTRUCTION TO REVISOR.] 
 31.19     The revisor of statutes shall renumber Minnesota Statutes, 
 31.20  section 116C.57, subdivision 6, as section 116C.57, subdivision 
 31.21  9. 
 31.22     Sec. 26.  [REPEALER.] 
 31.23     Minnesota Statutes 2000, sections 116C.55; 116C.57, 
 31.24  subdivisions 3, 5, and 5a; and 116C.67, are repealed. 
 31.25     Sec. 27.  [EFFECTIVE DATES.] 
 31.26     This article is effective the day following final 
 31.27  enactment, except that those provisions referring or relating to 
 31.28  article 1, section 2 or 3, the independent reliability 
 31.29  administrator or the state reliability plan, are effective July 
 31.30  1, 2002.  Section 2 does not apply to any proposal for a 
 31.31  transmission line between 100 and 200 kilovolts that is pending 
 31.32  before a local unit of government as of February 1, 2001. 
 31.33                             ARTICLE 3 
 31.34                       REGULATORY FLEXIBILITY 
 31.35     Section 1.  Minnesota Statutes 2000, section 216B.16, 
 31.36  subdivision 7, is amended to read: 
 32.1      Subd. 7.  [ENERGY COST ADJUSTMENT.] (a) Notwithstanding any 
 32.2   other provision of this chapter, the commission may permit a 
 32.3   public utility to file rate schedules containing provisions for 
 32.4   the automatic adjustment of charges for public utility service 
 32.5   in direct relation to changes in:  (1) federally regulated 
 32.6   wholesale rates for energy delivered through interstate 
 32.7   facilities; (2) direct costs for natural gas delivered; or (3) 
 32.8   costs for fuel used in generation of electricity or the 
 32.9   manufacture of gas. 
 32.10     (b) In reviewing utility fuel purchases under this or any 
 32.11  other provision, the commission shall allow and encourage a 
 32.12  utility to have a combination of measures to manage price 
 32.13  volatility and risk, including but not limited to having an 
 32.14  appropriate share of the utility's supply come from long-term 
 32.15  and medium-term contracts, in order to minimize consumer 
 32.16  exposure to fuel price volatility. 
 32.17     Sec. 2.  [216B.169] [RENEWABLE AND HIGH EFFICIENCY ENERGY 
 32.18  RATE OPTIONS.] 
 32.19     (a) Each public utility, cooperative association, and 
 32.20  municipal utility shall offer its customers and shall advertise 
 32.21  the offer at least annually one or more options that allow a 
 32.22  customer to determine that a certain amount of the electricity 
 32.23  generated or purchased on behalf of the customer is (1) 
 32.24  renewable energy as defined in section 216B.2422, subdivision 1, 
 32.25  paragraph (c), or (2) high-efficiency, low-emissions, 
 32.26  distributed generation such as fuel cells and microturbines 
 32.27  fueled by a renewable fuel. 
 32.28     (b) Each public utility shall file an implementation plan 
 32.29  within 90 days of the effective date of this section to 
 32.30  implement paragraph (a).  
 32.31     (c) Rates charged to customers must be calculated using the 
 32.32  utility's or association's cost of acquiring the energy for the 
 32.33  customer and must be (1) the difference between the cost of 
 32.34  generating or purchasing the renewable energy and the cost of 
 32.35  generating or purchasing the same amount of nonrenewable energy; 
 32.36  and (2) distributed on a per kilowatt-hour basis among all 
 33.1   customers who choose to participate in the program.  
 33.2   Implementation of these rate options may reflect a reasonable 
 33.3   amount of lead time necessary to arrange acquisition of the 
 33.4   energy.  
 33.5      (d) If a utility is not able to arrange an adequate supply 
 33.6   of renewable or high-efficiency energy to meet its customers' 
 33.7   demand under this section, the utility must file a report with 
 33.8   the commission detailing its efforts and reasons for its failure.
 33.9      (e) The commission, by order, may establish a program for 
 33.10  tradeable credits for renewable energy under this section. 
 33.11     Sec. 3.  Minnesota Statutes 2000, section 216B.241, 
 33.12  subdivision 1, is amended to read: 
 33.13     Subdivision 1.  [DEFINITIONS.] For purposes of this section 
 33.14  and section sections 216B.16, subdivision 6b, and 216B.2411, the 
 33.15  terms defined in this subdivision have the meanings given them.  
 33.16     (a) "Commission" means the public utilities commission. 
 33.17     (b) "Commissioner" means the commissioner of public service 
 33.18  commerce. 
 33.19     (c) "Customer facility" means all buildings, structures, 
 33.20  equipment, and installations at a single site. 
 33.21     (d) "Department" means the department of public 
 33.22  service commerce. 
 33.23     (e) "Energy conservation improvement" means the purchase or 
 33.24  installation of a device, method, material, or project that: 
 33.25     (1) reduces consumption of or increases efficiency in the 
 33.26  use of electricity or natural gas, including but not limited to 
 33.27  insulation and ventilation, storm or thermal doors or windows, 
 33.28  caulking and weatherstripping, furnace efficiency modifications, 
 33.29  thermostat or lighting controls, awnings, or systems to turn off 
 33.30  or vary the delivery of energy; 
 33.31     (2) either (i) creates, converts, or actively uses energy 
 33.32  from renewable sources such as solar, wind, and biomass, or (ii) 
 33.33  recovers energy for reuse, from air or water or other similar 
 33.34  material, provided that the device or method conforms with 
 33.35  national or state performance and quality standards whenever 
 33.36  applicable; 
 34.1      (3) seeks to provide energy savings through reclamation or 
 34.2   recycling and that is used as part of the infrastructure of an 
 34.3   electric generation, transmission, or distribution system within 
 34.4   the state or a natural gas distribution system within the state; 
 34.5   or 
 34.6      (4) provides research or development of new means of 
 34.7   increasing energy efficiency or conserving energy or research or 
 34.8   development of improvement of existing means of increasing 
 34.9   energy efficiency or conserving energy. 
 34.10     For a public utility, municipal utility, or cooperative 
 34.11  electric association that elects to be governed by section 
 34.12  216B.2411, the difference between the amount required to be 
 34.13  spent under that section and the amount that the utility would 
 34.14  have spent under this section may be used (i) for purposes of 
 34.15  making grants for the development of renewable energy 
 34.16  facilities, such as those utilizing agricultural wastes as 
 34.17  biomass fuel and methane digester facilities associated with 
 34.18  livestock feedlots for the production of energy, and requiring 
 34.19  the grants, to the extent feasible, to be coordinated with loans 
 34.20  under the shared savings loan program established in section 
 34.21  17.115, and (ii) for the purchase or installation of a device, 
 34.22  method, or project that increases a customer's ability to 
 34.23  control the amount and scheduling of energy purchased from a 
 34.24  utility, resulting in an overall decrease in energy consumption, 
 34.25  through the innovative installation of high-efficiency on-site 
 34.26  generation such as fuel cells or microturbines in combination 
 34.27  with other conservation initiatives, or through other 
 34.28  technologies to allow customers to manage their own load. 
 34.29     (f) "Investments and expenses of a public utility" includes 
 34.30  the investments and expenses incurred by a public utility in 
 34.31  connection with an energy conservation improvement, including 
 34.32  but not limited to:  
 34.33     (1) the differential in interest cost between the market 
 34.34  rate and the rate charged on a no-interest or below-market 
 34.35  interest loan made by a public utility to a customer for the 
 34.36  purchase or installation of an energy conservation improvement; 
 35.1      (2) the difference between the utility's cost of purchase 
 35.2   or installation of energy conservation improvements and any 
 35.3   price charged by a public utility to a customer for such 
 35.4   improvements.  
 35.5      (g) "Large electric customer facility" means a customer 
 35.6   facility that imposes a peak electrical demand on an electric 
 35.7   utility's system of not less than 20,000 10,000 kilowatts, 
 35.8   measured in the same way as the utility that serves the customer 
 35.9   facility measures electrical demand for billing purposes, and 
 35.10  for which electric services are provided at retail on a single 
 35.11  bill by a utility operating in the state. 
 35.12     Sec. 4.  Minnesota Statutes 2000, section 216B.241, 
 35.13  subdivision 1a, is amended to read: 
 35.14     Subd. 1a.  [INVESTMENT, EXPENDITURE, AND CONTRIBUTION; 
 35.15  PUBLIC UTILITY.] (a) For purposes of this subdivision and 
 35.16  subdivision 2, "public utility" has the meaning given it in 
 35.17  section 216B.02, subdivision 4.  Each public utility shall spend 
 35.18  and invest for energy conservation improvements under this 
 35.19  subdivision and subdivision 2 the following amounts: 
 35.20     (1) for a utility that furnishes gas service, 0.5 percent 
 35.21  of its gross operating revenues from service provided in the 
 35.22  state; 
 35.23     (2) for a utility that furnishes electric service, 1.5 
 35.24  percent of its gross operating revenues from service provided in 
 35.25  the state; and 
 35.26     (3) for a utility that furnishes electric service and that 
 35.27  operates a nuclear-powered electric generating plant within the 
 35.28  state, two percent of its gross operating revenues from service 
 35.29  provided in the state. 
 35.30  For purposes of this paragraph (a), "gross operating revenues" 
 35.31  do not include revenues from large electric customer facilities 
 35.32  exempted by the commissioner of the department of public service 
 35.33  pursuant to paragraph (b). 
 35.34     (b) The owner of a large electric customer facility may 
 35.35  petition the commissioner of the department of public 
 35.36  service commission to exempt both electric and gas utilities 
 36.1   serving the large energy customer facility from the investment 
 36.2   and expenditure requirements of paragraph (a) with respect to 
 36.3   retail revenues attributable to the facility.  At a minimum, the 
 36.4   petition must be supported by evidence relating to international 
 36.5   or domestic competitive or economic pressures on the customer 
 36.6   and a showing by the customer of reasonable efforts to identify, 
 36.7   evaluate, and implement cost-effective conservation improvements 
 36.8   at the facility.  The commission may grant the petition, 
 36.9   exempting both electric and gas utilities serving the large 
 36.10  energy customer facility from the investment and expenditure 
 36.11  requirements of paragraph (a) with respect to any percent of the 
 36.12  retail revenues attributable to the facility the commission 
 36.13  deems reasonable, upon a showing by the customer that it has 
 36.14  implemented all energy conservation improvements with a ten-year 
 36.15  simple payback or less, verified by a registered engineer or 
 36.16  other individual as authorized by the commission.  If a petition 
 36.17  is filed on or before October 1 of any year, the order of the 
 36.18  commissioner commission to exempt revenues attributable to the 
 36.19  facility can be effective no earlier than January 1 of the 
 36.20  following year.  The commissioner commission shall not grant an 
 36.21  exemption if the commissioner commission determines that 
 36.22  granting the exemption is contrary to the public interest.  
 36.23  The commissioner commission may, after investigation, rescind 
 36.24  any exemption granted under this paragraph upon a determination 
 36.25  that cost-effective energy conservation improvements are 
 36.26  available at the large electric customer facility.  For the 
 36.27  purposes of this paragraph, "cost-effective" means that the 
 36.28  projected total cost of the energy conservation improvement at 
 36.29  the large electric customer facility is less than the projected 
 36.30  present value of the energy and demand savings resulting from 
 36.31  the energy conservation improvement.  For the purposes of 
 36.32  investigations by the commissioner commission under this 
 36.33  paragraph, the owner of any large electric customer facility 
 36.34  shall, upon request, provide the commissioner commission with 
 36.35  updated information comparable to that originally supplied in or 
 36.36  with the owner's original petition under this paragraph. 
 37.1      (c) The commissioner may require investments or spending 
 37.2   greater than the amounts required under this subdivision for a 
 37.3   public utility whose most recent advance forecast required under 
 37.4   section 216B.2422 or 216C.17 projects a peak demand deficit of 
 37.5   100 megawatts or greater within five years under mid-range 
 37.6   forecast assumptions.  
 37.7      (d) A public utility or owner of a large electric customer 
 37.8   facility may appeal a decision of the commissioner under 
 37.9   paragraph (b) or (c) to the commission under subdivision 2.  In 
 37.10  reviewing a decision of the commissioner under paragraph (b) or 
 37.11  (c), the commission shall rescind the decision if it finds that 
 37.12  the required investments or spending will: 
 37.13     (1) not result in cost-effective energy conservation 
 37.14  improvements; or 
 37.15     (2) otherwise decision is not be in the public interest. 
 37.16     (e) Each utility shall determine what portion of the amount 
 37.17  it sets aside for conservation improvement will be used for 
 37.18  conservation improvements under subdivision 2 and what portion 
 37.19  it will contribute to the energy and conservation account 
 37.20  established in subdivision 2a.  A public utility may propose to 
 37.21  the commissioner to designate that all or a portion of funds 
 37.22  contributed to the account established in subdivision 2a be used 
 37.23  for research and development projects.  Contributions must be 
 37.24  remitted to the commissioner of public service by February 1 of 
 37.25  each year.  Nothing in this subdivision prohibits a public 
 37.26  utility from spending or investing for energy conservation 
 37.27  improvement more than required in this subdivision. 
 37.28     Sec. 5.  Minnesota Statutes 2000, section 216B.241, 
 37.29  subdivision 1b, is amended to read: 
 37.30     Subd. 1b.  [CONSERVATION IMPROVEMENT BY COOPERATIVE 
 37.31  ASSOCIATION OR MUNICIPALITY.] (a) This subdivision applies to: 
 37.32     (1) a cooperative electric association that generates and 
 37.33  transmits electricity to associations that provide electricity 
 37.34  at retail including a cooperative electric association not 
 37.35  located in this state that serves associations or others in the 
 37.36  state; 
 38.1      (2) a municipality that provides electric service to retail 
 38.2   customers; and 
 38.3      (3) a municipality with gross operating revenues in excess 
 38.4   of $5,000,000 from sales of natural gas to retail customers.  
 38.5      (b) Each cooperative electric association and municipality 
 38.6   subject to this subdivision shall spend and invest for energy 
 38.7   conservation improvements under this subdivision the following 
 38.8   amounts: 
 38.9      (1) for a municipality, 0.5 percent of its gross operating 
 38.10  revenues from the sale of gas and one percent of its gross 
 38.11  operating revenues from the sale of electricity not purchased 
 38.12  from a public utility governed by subdivision 1a or a 
 38.13  cooperative electric association governed by this subdivision, 
 38.14  excluding gross operating revenues from electric and gas service 
 38.15  provided in the state to large electric customer facilities; and 
 38.16     (2) for a cooperative electric association, 1.5 percent of 
 38.17  its gross operating revenues from service provided in the state, 
 38.18  excluding gross operating revenues from service provided in the 
 38.19  state to large electric customer facilities indirectly through a 
 38.20  distribution cooperative electric association. 
 38.21     (c) Each municipality and cooperative association subject 
 38.22  to this subdivision shall identify and implement energy 
 38.23  conservation improvement spending and investments that are 
 38.24  appropriate for the municipality or association, except that a 
 38.25  municipality or association may not spend or invest for energy 
 38.26  conservation improvements that directly benefit a large electric 
 38.27  customer facility.  Each municipality and cooperative electric 
 38.28  association subject to this subdivision may spend and invest 
 38.29  annually up to 15 percent of the total amount required to be 
 38.30  spent and invested on energy conservation improvements under 
 38.31  this subdivision on research and development projects that meet 
 38.32  the definition of energy conservation improvement in subdivision 
 38.33  1 and that are funded directly by the municipality or 
 38.34  cooperative electric association.  Load management may be used 
 38.35  to meet the requirements of this subdivision if it reduces the 
 38.36  demand for or increases the efficiency of electric services.  A 
 39.1   generation and transmission cooperative electric association may 
 39.2   include as spending and investment required under this 
 39.3   subdivision conservation improvement spending and investment by 
 39.4   cooperative electric associations that provide electric service 
 39.5   at retail to consumers and that are served by the generation and 
 39.6   transmission association. 
 39.7      (d) By February 1 of each year, each municipality or 
 39.8   cooperative shall report to the commissioner its energy 
 39.9   conservation improvement spending and investments with a brief 
 39.10  analysis of effectiveness in reducing consumption of electricity 
 39.11  or gas.  The commissioner shall review each report and make 
 39.12  recommendations, where appropriate, to the municipality or 
 39.13  association to increase the effectiveness of conservation 
 39.14  improvement activities.  The commissioner shall also review each 
 39.15  report for whether a portion of the money spent on residential 
 39.16  conservation improvement programs is devoted to programs that 
 39.17  directly address the needs of renters and low-income persons 
 39.18  unless an insufficient number of appropriate programs are 
 39.19  available.  For the purposes of this subdivision and subdivision 
 39.20  2, "low-income" means an income of less than 185 percent of the 
 39.21  federal poverty level. 
 39.22     (e) As part of its spending for conservation improvement, a 
 39.23  municipality or association may contribute to the energy and 
 39.24  conservation account.  A municipality or association may propose 
 39.25  to the commissioner to designate that all or a portion of funds 
 39.26  contributed to the account be used for research and development 
 39.27  projects.  Any amount contributed must be remitted to the 
 39.28  commissioner of public service by February 1 of each year.  
 39.29     Sec. 6.  Minnesota Statutes 2000, section 216B.241, 
 39.30  subdivision 2, is amended to read: 
 39.31     Subd. 2.  [PROGRAMS.] (a) The commissioner commission may 
 39.32  by rule or order require public utilities to make investments 
 39.33  and expenditures in energy conservation improvements, explicitly 
 39.34  setting forth the interest rates, prices, and terms under which 
 39.35  the improvements must be offered to the customers.  The required 
 39.36  programs must cover a two-year period.  The commissioner shall 
 40.1   require at least one public utility to establish a pilot program 
 40.2   to make investments in and expenditures for energy from 
 40.3   renewable resources such as solar, wind, or biomass and shall 
 40.4   give special consideration and encouragement to programs that 
 40.5   bring about significant net savings through the use of 
 40.6   energy-efficient lighting.  The commissioner commission shall 
 40.7   evaluate the program on the basis of cost-effectiveness and the 
 40.8   reliability of technologies employed.  The rules of the 
 40.9   department under this section must provide to the extent 
 40.10  practicable for a free choice, by consumers participating in the 
 40.11  program, of the device, method, material, or project 
 40.12  constituting the energy conservation improvement and for a free 
 40.13  choice of the seller, installer, or contractor of the energy 
 40.14  conservation improvement, provided that the device, method, 
 40.15  material, or project seller, installer, or contractor is duly 
 40.16  licensed, certified, approved, or qualified, including under the 
 40.17  residential conservation services program, where applicable.  
 40.18     (b) The commissioner commission may require a utility to 
 40.19  make an energy conservation improvement investment or 
 40.20  expenditure whenever the commissioner commission finds that the 
 40.21  improvement will result in energy savings at a total cost to the 
 40.22  utility less than the cost to the utility to produce or purchase 
 40.23  an equivalent amount of new supply of energy.  The commissioner 
 40.24  shall nevertheless ensure that every public utility operate one 
 40.25  or more programs under periodic review by the department.  Load 
 40.26  management may be used to meet the requirements for energy 
 40.27  conservation improvements under this section if it results in a 
 40.28  demonstrable reduction in consumption of energy.  Each public 
 40.29  utility subject to subdivision 1a may spend and invest annually 
 40.30  up to 15 percent of the total amount required to be spent and 
 40.31  invested on energy conservation improvements under this section 
 40.32  by the utility on research and development projects that meet 
 40.33  the definition of energy conservation improvement in subdivision 
 40.34  1 and that are funded directly by the public utility.  A public 
 40.35  utility may not spend for or invest in energy conservation 
 40.36  improvements that directly benefit a large electric customer 
 41.1   facility for which the commissioner commission has issued an 
 41.2   exemption pursuant to subdivision 1a, paragraph (b).  
 41.3   The commissioner commission shall consider and may require a 
 41.4   utility to undertake a program suggested by an outside source, 
 41.5   including a political subdivision or a nonprofit or community 
 41.6   organization. 
 41.7      (c) No utility may make an energy conservation improvement 
 41.8   under this section to a building envelope unless: 
 41.9      (1) it is the primary supplier of energy used for either 
 41.10  space heating or cooling in the building; 
 41.11     (2) the commissioner commission determines that special 
 41.12  circumstances, that would unduly restrict the availability of 
 41.13  conservation programs, warrant otherwise; or 
 41.14     (3) the utility has been awarded a contract under 
 41.15  subdivision 2a. 
 41.16     (d) The commissioner commission shall ensure that a portion 
 41.17  of the money spent on residential conservation improvement 
 41.18  programs is devoted to programs that directly address the needs 
 41.19  of renters and low-income persons unless an insufficient number 
 41.20  of appropriate programs are available. 
 41.21     (e) A utility, a political subdivision, or a nonprofit or 
 41.22  community organization that has suggested a program, the 
 41.23  attorney general acting on behalf of consumers and small 
 41.24  business interests, or a utility customer that has suggested a 
 41.25  program and is not represented by the attorney general under 
 41.26  section 8.33 may petition the commission to modify or revoke a 
 41.27  department decision under this section, and the commission may 
 41.28  do so if it determines that the program is not cost-effective, 
 41.29  does not adequately address the residential conservation 
 41.30  improvement needs of low-income persons, has a long-range 
 41.31  negative effect on one or more classes of customers, or is 
 41.32  otherwise not in the public interest.  The person petitioning 
 41.33  for commission review has the burden of proof.  The commission 
 41.34  shall reject a petition that, on its face, fails to make a 
 41.35  reasonable argument that a program is not in the public interest.
 41.36     Sec. 7.  Minnesota Statutes 2000, section 216B.241, is 
 42.1   amended by adding a subdivision to read: 
 42.2      Subd. 6.  [OVERVIEW; REVIEW AND AUDIT.] (a) For 
 42.3   conservation activities under section 216B.2411, each public 
 42.4   utility shall provide the commission with a prospective overview 
 42.5   of the utility's planned conservation activities and the 
 42.6   anticipated energy savings on a biennial basis, according to a 
 42.7   schedule established by the commission.  This overview shall 
 42.8   include a description of the types of activities, the consumer 
 42.9   sectors targeted by each, and the anticipated energy savings and 
 42.10  costs of each activity.  This overview shall also indicate, for 
 42.11  each type of activity, how much additional cost-effective 
 42.12  conservation is likely to be achieved in subsequent years.  In 
 42.13  addition, each public utility shall provide a report biennially 
 42.14  to the commission summarizing the public utility's actual 
 42.15  conservation activities over the previous two years, including, 
 42.16  for each activity, the utility's costs to the utility and to 
 42.17  participating customers, the utility's expected total energy 
 42.18  savings, the number of participating customers in each customer 
 42.19  class and consumer sector, and the activity's potential for 
 42.20  realizing additional cost-effective energy savings in the future.
 42.21     (b) Each public utility shall provide a report biennially 
 42.22  to the commission summarizing the public utility's conservation 
 42.23  activities and energy savings resulting from those activities 
 42.24  under either this section or section 216B.2411.  The public 
 42.25  utility shall include in the report the results of an 
 42.26  independent audit performed by the department or an auditor with 
 42.27  experience in the provision of energy conservation and energy 
 42.28  efficiency services approved by the commission.  The commission 
 42.29  shall issue a report comparing the overall effectiveness of the 
 42.30  conservation programs in overall cost, success in reducing 
 42.31  overall energy use, and energy saved per dollar spent. 
 42.32     (c) The audit provided under paragraph (b) shall evaluate 
 42.33  whether the public utility has implemented cost-effective energy 
 42.34  conservation programs.  In making this evaluation, the audit 
 42.35  shall consider whether the public utility's programs (1) fairly 
 42.36  address each of the utility's consumer classes and market 
 43.1   sectors, (2) use accurate data in calculating costs and energy 
 43.2   savings, and (3) indicate an adequate commitment to implementing 
 43.3   cost-effective conservation programs.  Up to five percent of a 
 43.4   utility's conservation spending obligation under this section or 
 43.5   section 216B.2411 may be used for program pre-evaluation, 
 43.6   research and testing, monitoring, and program evaluation. 
 43.7      (d) Following two or more negative evaluations under 
 43.8   paragraph (b), the commission may determine that a public 
 43.9   utility is not implementing adequate energy conservation 
 43.10  programs under section 216B.2411.  In that event, the commission 
 43.11  may order the utility or association to commit an appropriate 
 43.12  amount of its conservation spending obligations under those 
 43.13  sections to providing conservation programs under section 
 43.14  216B.241. 
 43.15     Sec. 8.  Minnesota Statutes 2000, section 216B.241, is 
 43.16  amended by adding a subdivision to read: 
 43.17     Subd. 7.  [ADDITIONAL CONSERVATION SPENDING.] (a) Nothing 
 43.18  in this section or section 216B.2411 prohibits any energy 
 43.19  utility from spending or investing more for energy conservation 
 43.20  improvements than is required in those sections. 
 43.21     (b) The commission may require a public utility to invest 
 43.22  or spend more than is required under this section or section 
 43.23  216B.2411 if the commission finds that additional investments 
 43.24  would be cost effective, and the utility's most recent forecast 
 43.25  projects a significant demand deficit. 
 43.26     Sec. 9.  [216B.2411] [CONSERVATION INVESTMENT PROGRAM.] 
 43.27     Subdivision 1.  [DEFINITIONS.] The definitions in section 
 43.28  216B.241 apply to this section. 
 43.29     Subd. 2.  [INVESTMENTS.] (a) A public utility, 
 43.30  municipality, or cooperative electric association may elect to 
 43.31  be governed by this section rather than section 216B.241, by 
 43.32  notifying the commission of its election.  However, section 
 43.33  216B.241, subdivisions 1a, paragraph (b); 1b, paragraph (c); and 
 43.34  2b, apply to conservation investments made under this section. 
 43.35     (b) Each entity that elects to be governed by this section 
 43.36  shall spend and invest for energy conservation improvements the 
 44.1   following amounts: 
 44.2      (1) for a public utility that furnishes gas service, 0.75 
 44.3   percent of the utility's annual average gross operating revenues 
 44.4   over the previous five years from service provided in this 
 44.5   state; 
 44.6      (2) for a cooperative electric association that provides 
 44.7   electricity at retail or a public utility that furnishes 
 44.8   electric service, two percent of the utility's or association's 
 44.9   annual average gross operating revenues over the previous five 
 44.10  years from service provided in this state; 
 44.11     (3) for a utility that furnishes electric service and that 
 44.12  operates a nuclear-powered electric generating plant within the 
 44.13  state, three percent of the utility's annual average gross 
 44.14  operating revenues over the previous five years from service 
 44.15  provided in this state; and 
 44.16     (4) for a municipality, 0.75 percent of the utility's 
 44.17  annual average gross operating revenues over the previous five 
 44.18  years from the sale of gas and 1.5 percent of the utility's 
 44.19  annual average gross operating revenues over the previous five 
 44.20  years from the sale of electricity not purchased from a public 
 44.21  utility or a cooperative electric association governed by this 
 44.22  subdivision over its five-year conservation spending average. 
 44.23  For purposes of this paragraph, "gross operating revenues" do 
 44.24  not include revenues from large electric customer facilities 
 44.25  exempted by the commissioner pursuant to section 216B.241, 
 44.26  subdivision 1a, paragraph (b).  Entities electing to be governed 
 44.27  by this section shall comply with section 216B.241, subdivision 
 44.28  6. 
 44.29     Sec. 10.  [452.25] [JOINT VENTURE.] 
 44.30     Subdivision 1.  [APPLICABILITY.] This section applies to 
 44.31  all home rule charter and statutory cities. 
 44.32     Subd. 2.  [DEFINITIONS.] These phrases have the meanings 
 44.33  given them in this section. 
 44.34     (a) "Municipal utility" means the operations of a city with 
 44.35  respect to any public utilities. 
 44.36     (b) "Municipal power agency" means any organization created 
 45.1   under sections 453.51 to 453.62. 
 45.2      (c) "Governing body" means, with respect to each city that 
 45.3   operates a municipal utility, the city council, or if another 
 45.4   board, commission, or body is empowered by law or city charter 
 45.5   or by ordinance or resolution of the city council to control and 
 45.6   operate the municipal utility, the board, commission, or body is 
 45.7   the governing body. 
 45.8      (d) "Cooperative association" means a distribution 
 45.9   cooperative association organized under chapter 308A and engaged 
 45.10  primarily in retail public utilities operations. 
 45.11     (e) "Public utility" or "utility" means electric, water, or 
 45.12  telecommunications services or other similar or related 
 45.13  operations authorized by law or charter. 
 45.14     (f) "Investor-owned utility" means an entity that provides 
 45.15  utility services to the public and that is owned by private 
 45.16  persons, including utilities governed by chapters 216B and 237.  
 45.17     Subd. 3.  [AUTHORIZATION.] (a) Municipal utilities may 
 45.18  enter into joint ventures with other municipal utilities, 
 45.19  municipal power agencies, cooperative associations, or investor- 
 45.20  owned utilities, to provide utility services.  Retail electric 
 45.21  utility services provided by a joint venture must be within the 
 45.22  boundaries of each utility's exclusive electric service 
 45.23  territory as shown on the map of service territories maintained 
 45.24  by the department of commerce.  The terms and conditions of the 
 45.25  joint venture are subject to ratification by the governing 
 45.26  bodies of the respective utilities and may include the formation 
 45.27  of a corporate or other separate legal entity with an 
 45.28  administrative and governance structure independent of the 
 45.29  respective utilities. 
 45.30     (b) A corporate or other separate legal entity, if formed: 
 45.31     (1) has the authority and legal capacity, and in the 
 45.32  exercise of joint venture powers, privileges, responsibilities, 
 45.33  and duties authorized by this section, is subject to the law 
 45.34  applicable to the organization, internal governance, and 
 45.35  activities of the entity; 
 45.36     (2) may exercise in connection with its property and 
 46.1   affairs, and in connection with property within its control, any 
 46.2   and all powers that may be exercised by a natural person or a 
 46.3   private corporation or other private legal entity in connection 
 46.4   with similar property and affairs; and 
 46.5      (3) is not a public body or authority, government entity, 
 46.6   municipal corporation, or political subdivision, except that, 
 46.7   regardless of its form of organization, a joint venture, 
 46.8   including any separate legal entity, if formed between municipal 
 46.9   utilities, municipal power agencies, and cooperative 
 46.10  associations, may elect to be deemed a municipal utility or a 
 46.11  cooperative association for purposes of chapter 216B or other 
 46.12  federal or state law regulating utility operations. 
 46.13     Subd. 4.  [RETAIL CUSTOMERS.] The retail electric customers 
 46.14  of the joint venture may elect to become subject to electric 
 46.15  rate regulation by the public utilities commission as now 
 46.16  provided in sections 216B.03 to 216B.23.  The election must be 
 46.17  subject to and carried out according to the procedures in 
 46.18  section 216B.026 and for such purposes, each retail electric 
 46.19  customer of the joint venture must be deemed a member or 
 46.20  stockholder as referred to in section 261B.026.  
 46.21     Subd. 5.  [POWERS.] (a) A joint venture under this section 
 46.22  has those powers, privileges, responsibilities, and duties of 
 46.23  the separate utilities entering into the joint venture as the 
 46.24  joint venture agreement may provide, including the powers under 
 46.25  paragraph (b), except that (1) with respect to retail electric 
 46.26  utility services, neither the joint venture nor any member 
 46.27  municipal utility may enlarge or extend the service territory 
 46.28  served by the joint venture and (2) the joint venture shall not 
 46.29  extend service to an existing connected load of 2,000 kilowatts 
 46.30  or more, pursuant to section 216B.42, if the load is outside of 
 46.31  the assigned service area of the joint venture, or of the 
 46.32  electric utilities party to the joint venture, unless the load 
 46.33  is already being served by one of the electric utilities party 
 46.34  to the joint venture.  A public utility, as defined in section 
 46.35  216B.02, may not extend service to any existing connected load 
 46.36  of 2,000 kilowatts or more pursuant to section 216B.42 if the 
 47.1   load is located within the assigned service territory of a joint 
 47.2   venture or of the electric utilities that are members of the 
 47.3   joint venture, unless the load is already being served by that 
 47.4   privately owned utility.  The limitations of clauses (1) and (2) 
 47.5   shall not apply if written consent is obtained from the electric 
 47.6   utility assigned to and serving the affected service territory 
 47.7   or connected load.  This subdivision does not limit the 
 47.8   authority of a joint venture to exercise rights of eminent 
 47.9   domain for utility purposes other than those described in this 
 47.10  subdivision, to the same extent as the members of the joint 
 47.11  venture. 
 47.12     (b) Joint venture powers include, but are not limited to, 
 47.13  the authority to: 
 47.14     (1) finance, own, acquire, construct, and operate 
 47.15  facilities necessary to provide utility services to retail 
 47.16  customers of the joint venture, including generation, 
 47.17  transmission, and distribution facilities, and like facilities 
 47.18  used in other utility services; 
 47.19     (2) combine assigned service territories, in whole or in 
 47.20  part, upon notice to, hearing by, and approval of the public 
 47.21  utilities commission; 
 47.22     (3) serve customers in the utilities' service territories 
 47.23  or in the combined service territory; 
 47.24     (4) combine, share, or employ administrative, managerial, 
 47.25  operational, or other staff if combining or sharing will not 
 47.26  degrade safety, reliability, or customer service standards; 
 47.27     (5) provide for joint administrative functions, such as 
 47.28  meter reading and billings; 
 47.29     (6) purchase or sell utility services at wholesale for 
 47.30  resale to customers; 
 47.31     (7) provide conservation programs, other utility programs, 
 47.32  and public interest programs, such as cold weather shut-off 
 47.33  protection and conservation spending programs, as required by 
 47.34  law and rule; and 
 47.35     (8) participate as the parties deem necessary in providing 
 47.36  utility services with other municipal utilities, cooperative 
 48.1   utilities, investor-owned utilities, or other entities, public 
 48.2   or private.  
 48.3      (c) Notwithstanding any contrary provision within this 
 48.4   section, a joint venture formed under this section may engage in 
 48.5   wholesale utility services unless the municipal utility, the 
 48.6   municipal power agency, the cooperative association, or the 
 48.7   investor-owned utility party to the joint venture is prohibited 
 48.8   under current law to conduct that activity.  However, the joint 
 48.9   venture may provide wholesale services to a municipal utility, a 
 48.10  cooperative association, or an investor-owned utility that is a 
 48.11  member of the joint venture.  
 48.12     Subd. 6.  [CONSTRUCTION.] (a) This section must be 
 48.13  construed liberally to effect its legislative intent and 
 48.14  purpose, as complete and independent authority for the 
 48.15  performance of each and every act and thing authorized by this 
 48.16  section.  All authority granted must be broadly interpreted to 
 48.17  effect this intent and purpose and not as a limit of powers.  
 48.18  The powers conferred by this section are in addition to the 
 48.19  powers conferred by other law or charter.  A joint venture under 
 48.20  this section, and a municipal utility with respect to any joint 
 48.21  venture under this section, has the powers, privileges, 
 48.22  responsibilities, and duties necessary or appropriate to effect 
 48.23  the intent and purpose of this section, including, but not 
 48.24  limited to, the expenditure of public funds and the transfer of 
 48.25  real or personal property in accordance with the terms and 
 48.26  conditions of the joint venture and the joint venture 
 48.27  agreement.  This section is complete in itself with respect to 
 48.28  the formation and operation of a joint venture under this 
 48.29  section and with respect to a municipal utility, a cooperative 
 48.30  association, or an investor-owned utility party to a joint 
 48.31  venture related to their creation of and dealings with the joint 
 48.32  venture, without regard to other laws or city charter provisions 
 48.33  that do not specifically address or refer to this section or a 
 48.34  joint venture created under this section. 
 48.35     (b) This section must not be construed to supersede or 
 48.36  modify: 
 49.1      (1) the power of a city council conferred by charter to 
 49.2   overrule or override any action of a governing body other than 
 49.3   the actions of the joint venture; 
 49.4      (2) chapter 216B, except as specifically provided in this 
 49.5   section; 
 49.6      (3) any referendum requirements applicable to the creation 
 49.7   of a new electric utility by a municipality under section 
 49.8   216B.46 or 216B.465 or establishment of a telephone exchange by 
 49.9   a municipality under section 237.19; 
 49.10     (4) any powers, privileges, or authority or any duties or 
 49.11  obligations of a municipal utility, a municipal power agency, or 
 49.12  a cooperative association acting as a separate legal entity 
 49.13  without reference to a joint venture created under this section. 
 49.14     Sec. 11.  [CONSERVATION IMPROVEMENT PLAN; EVALUATION OF 
 49.15  COOPERATIVE AND MUNICIPAL PROGRAMS.] 
 49.16     (a) Cooperative electric association and municipal 
 49.17  utilities shall evaluate their energy and capacity conservation 
 49.18  programs, develop plans for future programs, and report their 
 49.19  findings and plans to the chairs of the house of representatives 
 49.20  and senate committees with jurisdiction over energy issues by 
 49.21  February 15, 2002.  The evaluation shall address: 
 49.22     (1) whether the utility or association has implemented and 
 49.23  is implementing cost-effective energy conservation programs and 
 49.24  shall specify the actual energy and capacity savings within the 
 49.25  service territory or association that is the result of 
 49.26  conservation improvement programs using a list of uniform 
 49.27  baseline energy and capacity savings assumptions developed by 
 49.28  the department of commerce; 
 49.29     (2) the availability of basic conservation services and 
 49.30  programs to customers; 
 49.31     (3) methodologies that best quantify energy savings, cost 
 49.32  effectiveness, and the potential for cost-effective conservation 
 49.33  improvements; 
 49.34     (4) the value of local administration of conservation 
 49.35  programs in meeting local and statewide needs; 
 49.36     (5) the effect on customer bills; 
 50.1      (6) the role of capacity conservation in meeting utility 
 50.2   planning needs and state energy goals; 
 50.3      (7) the ability of energy conservation programs to avoid 
 50.4   the need for construction of generation facilities and 
 50.5   transmission lines; 
 50.6      (8) whether the utility's or association's programs address 
 50.7   all of the following consumer market sectors:  farm, 
 50.8   residential, commercial, and industrial; and 
 50.9      (9) whether the utility's or association's programs use 
 50.10  accurate and auditable data in calculating costs and energy 
 50.11  savings. 
 50.12     (b) Municipal utilities and cooperative electric 
 50.13  associations must consult with the department of commerce in 
 50.14  preparing this report.  The evaluation shall develop program and 
 50.15  performance goals that recognize customer class, utility service 
 50.16  area demographics, cost of program delivery, regional economic 
 50.17  indicators, and utility load shape.  The cost of the evaluation 
 50.18  may be deducted from the utility's or association's conservation 
 50.19  spending obligation under section 216B.241 or 216B.2411. 
 50.20                             ARTICLE 4
 50.21              INTERCONNECTION OF DISTRIBUTED RESOURCES
 50.22     Section 1.  [216B.68] [DEFINITIONS.] 
 50.23     Subdivision 1.  [SCOPE.] The words and terms used in 
 50.24  sections 216B.68 to 216B.75 have the meanings given them in this 
 50.25  section. 
 50.26     Subd. 2.  [APPLICATION FOR INTERCONNECTION AND PARALLEL 
 50.27  OPERATION.] "Application for interconnection and parallel 
 50.28  operation" with the utility system or application means a 
 50.29  standard form of application developed by the commissioner and 
 50.30  approved by the commission. 
 50.31     Subd. 3.  [COMPANY.] "Company" means an electric utility 
 50.32  operating a distribution system. 
 50.33     Subd. 4.  [ELECTRIC UTILITY.] "Electric utility" means all 
 50.34  electric utilities that own and operate equipment in the state 
 50.35  for furnishing electric service at retail. 
 50.36     Subd. 5.  [CUSTOMER.] "Customer" means any individual 
 51.1   person or entity interconnected to the company's utility system 
 51.2   for the purpose of receiving or exporting electric power from or 
 51.3   to the company's utility system. 
 51.4      Subd. 6.  [DISTRIBUTED GENERATION OR ON-SITE DISTRIBUTED 
 51.5   GENERATION.] "Distributed generation" or "on-site distributed 
 51.6   generation" means an electrical generating facility located at a 
 51.7   customer's point of delivery or point of common coupling of ten 
 51.8   megawatts or less and connected at a voltage less than or equal 
 51.9   to 60 kilovolts that may be connected in parallel operation to 
 51.10  the utility system. 
 51.11     Subd. 7.  [FACILITY.] "Facility" means an electrical 
 51.12  generating installation consisting of one or more on-site 
 51.13  distributed generation units.  The total capacity of a 
 51.14  facility's individual on-site distributed generation units may 
 51.15  exceed ten megawatts; however, no more than ten megawatts of a 
 51.16  facility's capacity will be interconnected at any point in time 
 51.17  at the point of common coupling under this section. 
 51.18     Subd. 8.  [INTERCONNECTION.] "Interconnection" means the 
 51.19  physical connection of distributed generation to the utility 
 51.20  system in accordance with the requirements of this section so 
 51.21  that parallel operation can occur. 
 51.22     Subd. 9.  [INTERCONNECTION AGREEMENT.] "Interconnection 
 51.23  agreement" means the standard form of agreement, developed and 
 51.24  approved by the commission.  The interconnection agreement sets 
 51.25  forth the contractual conditions under which a company and a 
 51.26  customer agree that one or more facilities may be interconnected 
 51.27  with the company's utility system. 
 51.28     Subd. 10.  [INVERTER-BASED PROTECTIVE 
 51.29  FUNCTION.] "Inverter-based protective function" means a function 
 51.30  of an inverter system, carried out using hardware and software, 
 51.31  that is designed to prevent unsafe operating conditions from 
 51.32  occurring before, during, and after the interconnection of an 
 51.33  inverter-based static power converter unit with a utility 
 51.34  system.  For purposes of this definition, unsafe operating 
 51.35  conditions are conditions that, if left uncorrected, would 
 51.36  result in harm to personnel, damage to equipment, unacceptable 
 52.1   system instability, or operation outside legally established 
 52.2   parameters affecting the quality of service to other customers 
 52.3   connected to the utility system. 
 52.4      Subd. 11.  [NETWORK SERVICE.] "Network service" means two 
 52.5   or more utility primary distribution feeder sources electrically 
 52.6   tied together on the secondary side, which is the low-voltage 
 52.7   side, to form one power source for one or more customers.  The 
 52.8   service is designed to maintain service to the customers even 
 52.9   after the loss of one of these primary distribution feeder 
 52.10  sources. 
 52.11     Subd. 12.  [PARALLEL OPERATION.] "Parallel operation" means 
 52.12  the operation of on-site distributed generation by a customer 
 52.13  while the customer is connected to the company's utility system. 
 52.14     Subd. 13.  [POINT OF COMMON COUPLING.] "Point of common 
 52.15  coupling" means the point where the electrical conductors of the 
 52.16  company utility system are connected to the customer's 
 52.17  conductors and where any transfer of electric power between the 
 52.18  customer and the utility system takes place, such as switchgear 
 52.19  near the meter. 
 52.20     Subd. 14.  [PRECERTIFIED EQUIPMENT.] "Precertified 
 52.21  equipment" means a specific generating and protective equipment 
 52.22  system or systems that have been certified as meeting the 
 52.23  applicable parts of this section relating to safety and 
 52.24  reliability by an entity approved by the commission. 
 52.25     Subd. 15.  [PRE-INTERCONNECTION STUDY.] 
 52.26  "Pre-interconnection study" means a study or studies that may be 
 52.27  undertaken by a company in response to its receipt of a 
 52.28  completed application for interconnection and parallel operation 
 52.29  with the utility system.  Pre-interconnection studies may 
 52.30  include, but are not limited to, service studies, coordination 
 52.31  studies, and utility system impact studies. 
 52.32     Subd. 16.  [STABILIZED.] "Stabilized" means that, following 
 52.33  a disturbance, a company utility system has returned to the 
 52.34  normal range of voltage and frequency for a duration of two 
 52.35  minutes or a shorter time as mutually agreed to by the company 
 52.36  and customer. 
 53.1      Subd. 17.  [TARIFF OR TARIFF FOR INTERCONNECTION AND 
 53.2   PARALLEL OPERATION OF DISTRIBUTED GENERATION.] "Tariff" or 
 53.3   "Tariff for interconnection and parallel operation of 
 53.4   distributed generation" means the commission-developed and 
 53.5   commission-approved tariff for interconnection and parallel 
 53.6   operation of distributed generation, including the application 
 53.7   for interconnection and parallel operation of distributed 
 53.8   generation and pre-interconnection study fee schedule. 
 53.9      Subd. 18.  [UNIT.] "Unit" means a power generator. 
 53.10     Subd. 19.  [UTILITY SYSTEM.] "Utility system" means a 
 53.11  company's distribution system below 60 kilovolts to which the 
 53.12  generation equipment is interconnected. 
 53.13     Sec. 2.  [216B.69] [INTERCONNECTION OF ON-SITE DISTRIBUTED 
 53.14  GENERATION.] 
 53.15     Subdivision 1.  [PURPOSE.] The purpose of sections 216B.68 
 53.16  to 216B.75 is to state the terms and conditions that govern the 
 53.17  interconnection and parallel operation of on-site distributed 
 53.18  generation to provide cost savings and reliability benefits to 
 53.19  customers, to establish technical requirements that will promote 
 53.20  the safe and reliable parallel operation of on-site distributed 
 53.21  generation resources, to enhance both the reliability of 
 53.22  electric service and economic efficiency in the production and 
 53.23  consumption of electricity, and to promote the use of 
 53.24  distributed resources in order to provide electric system 
 53.25  benefits during periods of capacity constraints. 
 53.26     Subd. 2.  [OBLIGATION TO SERVE; TARIFF AND OTHER 
 53.27  FILINGS.] (a) No later than 270 days after the effective date of 
 53.28  this section, each electric utility shall file tariffs for 
 53.29  interconnection and parallel operation of distributed generation 
 53.30  in conformance with sections 216B.68 to 216B.75.  The electric 
 53.31  utility may file a new tariff or a modification of an existing 
 53.32  tariff.  These tariffs must ensure that backup power, 
 53.33  supplemental power, and maintenance power are available to all 
 53.34  customers and customer classes that desire this service.  Any 
 53.35  modifications of existing tariffs or offerings of new tariffs 
 53.36  relating to this section must be consistent with the 
 54.1   commission-approved form.  
 54.2      (b) Concurrent with the tariff filing in this section, each 
 54.3   utility shall submit: 
 54.4      (1) a schedule detailing the charges of interconnection 
 54.5   studies and all supporting cost data for the charges; 
 54.6      (2) a standard application for interconnection and parallel 
 54.7   operation of distributed generation; and 
 54.8      (3) the interconnection agreement approved by the 
 54.9   commission. 
 54.10     Sec. 3.  [216B.70] [DISCONNECTION AND RECONNECTION.] 
 54.11     Subdivision 1.  [WHEN DISCONNECTION ALLOWED.] A utility may 
 54.12  disconnect a distributed generation unit from the utility system 
 54.13  if: 
 54.14     (1) the interconnection agreement with a customer expires 
 54.15  or terminates, in accordance with the terms of the agreement; 
 54.16     (2) the facility is not in compliance with the technical 
 54.17  requirements specified by the commissioner; 
 54.18     (3) continued interconnection will endanger persons or 
 54.19  property; or 
 54.20     (4) written notice is provided at least seven business days 
 54.21  prior to a service interruption for routine maintenance, 
 54.22  repairs, and utility system modifications. 
 54.23     Subd. 2.  [INCREMENTAL DEMAND CHARGES.] During the term of 
 54.24  an interconnection agreement, a utility may require that a 
 54.25  customer disconnect its distributed generation unit or take it 
 54.26  off-line as a result of utility system conditions.  The company 
 54.27  may not assess the customer incremental demand charges arising 
 54.28  from disconnecting the distributed generator as directed by the 
 54.29  company during these periods. 
 54.30     Sec. 4.  [216B.71] [PRE-INTERCONNECTION STUDIES FOR 
 54.31  NONNETWORK INTERCONNECTION OF DISTRIBUTED GENERATION.] 
 54.32     Subdivision 1.  [STUDIES.] A utility may conduct a service 
 54.33  study, coordination study, or utility system impact study prior 
 54.34  to interconnection of a distributed generation facility.  When a 
 54.35  study is deemed necessary, the scope of the study must be based 
 54.36  on the characteristics of the particular distributed generation 
 55.1   facility to be interconnected and the utility's system at the 
 55.2   specific proposed location.  By agreement between the utility 
 55.3   and its customer, a study related to interconnection of 
 55.4   distributed generation on the customer's premises may be 
 55.5   conducted by a qualified third party. 
 55.6      Subd. 2.  [CUSTOMER FEE.] (a) A utility may not charge a 
 55.7   customer a fee to conduct a pre-interconnection study for 
 55.8   precertified distributed generation units up to 500 kilowatts 
 55.9   that export not more than 15 percent of the total load on a 
 55.10  single radial feeder and contribute not more than 25 percent of 
 55.11  the maximum potential short circuit current on a single radial 
 55.12  feeder. 
 55.13     (b) Prior to the interconnection of a distributed 
 55.14  generation facility not described in paragraph (a), a utility 
 55.15  may charge a customer a fee to offset its costs incurred in the 
 55.16  conduct of a pre-interconnection study.  
 55.17     Subd. 3.  [WHEN UTILITY CONDUCTS STUDY.] When a utility 
 55.18  conducts an interconnection study, paragraphs (a) to (d) apply: 
 55.19     (a) The conduct of the pre-interconnection study may not 
 55.20  take more than four weeks. 
 55.21     (b) A utility shall prepare written reports of the study 
 55.22  findings and make them available to the customer. 
 55.23     (c) The study must consider both the costs incurred and the 
 55.24  benefits realized as a result of the interconnection of 
 55.25  distributed generation to the company's utility system. 
 55.26     (d) The utility shall provide the customer with an estimate 
 55.27  of the study cost before the utility initiates the study. 
 55.28     Sec. 5.  [216B.72] [PRE-INTERCONNECTION STUDIES FOR NETWORK 
 55.29  INTERCONNECTION OF DISTRIBUTED GENERATION.] 
 55.30     Subdivision 1.  [NOTICE AND FEES.] (a) Prior to charging a 
 55.31  pre-interconnection study fee for a network interconnection of 
 55.32  distributed generation, a utility shall first advise the 
 55.33  customer of the potential problems associated with 
 55.34  interconnection of distributed generation with its network 
 55.35  system.  
 55.36     (b) For potential interconnections to network systems, a 
 56.1   pre-interconnection study fee may not be assessed for a facility 
 56.2   with inverter systems under 20 kilowatts.  For all other 
 56.3   facilities, the utility may charge the customer a fee to offset 
 56.4   its costs incurred in the conduct of the pre-interconnection 
 56.5   study.  
 56.6      Subd. 2.  [REQUIREMENTS WHEN UTILITY CONDUCTS STUDY.] When 
 56.7   a utility conducts an interconnection study, paragraphs (a) to 
 56.8   (d) apply: 
 56.9      (a) The conduct of a pre-interconnection study may not take 
 56.10  more than four weeks. 
 56.11     (b) A utility shall prepare written reports of the study 
 56.12  findings and make them available to the customer. 
 56.13     (c) The study must consider both the costs incurred and the 
 56.14  benefits realized as a result of the interconnection of 
 56.15  distributed generation to the utility's system. 
 56.16     (d) The utility shall provide the customer with an estimate 
 56.17  of the study cost before the utility initiates the study. 
 56.18     Sec. 6.  [216B.73] [EQUIPMENT PRECERTIFICATION.] (a) The 
 56.19  commission may approve one or more entities that shall 
 56.20  precertify equipment as described under this section. 
 56.21     (b) Testing organizations or facilities capable of 
 56.22  analyzing the function, control, and protective systems of 
 56.23  distributed generation units may request to be certified as 
 56.24  testing organizations. 
 56.25     (c) Distributed generation units that are certified to be 
 56.26  in compliance by an approved testing facility or organization 
 56.27  must be installed on a company utility system in accordance with 
 56.28  an approved interconnection control and protection scheme 
 56.29  without further review of their design by the utility. 
 56.30     Sec. 7.  [216B.74] [TIME FOR PROCESSING APPLICATIONS FOR 
 56.31  INTERCONNECTION.] 
 56.32     (a) The interconnection of distributed generation to the 
 56.33  utility system must take place within the schedules described in 
 56.34  paragraphs (b) to (f): 
 56.35     (b) For a facility with precertified equipment, 
 56.36  interconnection must take place within four weeks of the 
 57.1   utility's receipt of a completed interconnection application. 
 57.2      (c) For facilities without precertified equipment, 
 57.3   connection must take place within six weeks of the utility's 
 57.4   receipt of a completed application. 
 57.5      (d) If interconnection of a particular facility will 
 57.6   require substantial capital upgrades to the utility system, the 
 57.7   company shall provide the customer an estimate of the schedule 
 57.8   and the customer's cost for the upgrade.  If the customer 
 57.9   desires to proceed with the upgrade, the customer and the 
 57.10  company shall enter into a contract for the completion of the 
 57.11  upgrade.  The interconnection must take place no later than two 
 57.12  weeks following the completion of the upgrade.  The utility 
 57.13  shall employ best reasonable efforts to complete the system 
 57.14  upgrade in the shortest time reasonably practical. 
 57.15     (e) A utility shall use best reasonable efforts to 
 57.16  interconnect facilities within the time frames described in this 
 57.17  section.  If in a particular instance, a utility determines that 
 57.18  it cannot interconnect a facility within the time frames stated 
 57.19  in this section, it must notify the applicant in writing of that 
 57.20  fact.  The notification must identify any reasons 
 57.21  interconnection could not be performed in accordance with the 
 57.22  schedule and provide an estimated date for interconnection. 
 57.23     (f) Applications for interconnection and parallel operation 
 57.24  of distributed generation must be processed by the utility in a 
 57.25  nondiscriminatory manner and in the order that they are 
 57.26  received.  It is recognized that certain applications may 
 57.27  require minor modifications while they are being reviewed by the 
 57.28  utility.  These minor modifications to a pending application do 
 57.29  not require that it be considered incomplete and treated as a 
 57.30  new or separate application. 
 57.31     Sec. 8.  [216B.75] [REPORTING REQUIREMENTS.] 
 57.32     (a) Each electric utility shall maintain records concerning 
 57.33  applications received for interconnection and parallel operation 
 57.34  of distributed generation.  The records must include the date 
 57.35  each application is received, documents generated in the course 
 57.36  of processing each application, correspondence regarding each 
 58.1   application, and the final disposition of each application.  
 58.2      (b) By March 30 of each year, every electric utility shall 
 58.3   file with the commission a distributed generation 
 58.4   interconnection report for the preceding calendar year that 
 58.5   identifies each distributed generation facility interconnected 
 58.6   with the utility's distribution system.  The report must list 
 58.7   the new distributed generation facilities interconnected with 
 58.8   the system since the previous year's report, any distributed 
 58.9   generation facilities no longer interconnected with the 
 58.10  utility's system since the previous report, the capacity of each 
 58.11  facility, and the feeder or other point on the company's utility 
 58.12  system where the facility is connected.  The annual report must 
 58.13  also identify all applications for interconnection received 
 58.14  during the previous one-year period, and the disposition of the 
 58.15  applications. 
 58.16                             ARTICLE 5 
 58.17                       CONFORMING AMENDMENTS 
 58.18     Section 1.  Minnesota Statutes 2000, section 116C.61, 
 58.19  subdivision 1, is amended to read: 
 58.20     Subdivision 1.  [REGIONAL, COUNTY AND LOCAL ORDINANCES, 
 58.21  RULES, REGULATIONS; PRIMARY RESPONSIBILITY AND REGULATION OF 
 58.22  SITE DESIGNATION, IMPROVEMENT, AND USE.] To assure the paramount 
 58.23  and controlling effect of the provisions herein this section 
 58.24  over other state agencies,; regional, county, and local 
 58.25  governments,; and special purpose government districts, the 
 58.26  issuance of a certificate of site compatibility permit or 
 58.27  transmission line construction route permit and subsequent 
 58.28  purchase and use of such site or route locations for large 
 58.29  electric power generating plant and high voltage transmission 
 58.30  line purposes shall be is the sole site approval required to be 
 58.31  obtained by the utility.  Such certificate or The permit shall 
 58.32  supersede supersedes and preempt all preempts any zoning, 
 58.33  building, or land use rules, regulations, or ordinances 
 58.34  promulgated by any regional, county, local, and special purpose 
 58.35  government. 
 58.36     Sec. 2.  Minnesota Statutes 2000, section 116C.62, is 
 59.1   amended to read: 
 59.2      116C.62 [IMPROVEMENT OF SITES AND ROUTES.] 
 59.3      Utilities which that have acquired a site or route in 
 59.4   accordance with sections 116C.51 to 116C.69 may proceed to 
 59.5   construct or improve the site or route for the intended purposes 
 59.6   at any time, subject to section 116C.61, subdivision 2,; 
 59.7   provided that, if the construction and improvement commences 
 59.8   more than has not commenced within four years after a 
 59.9   certificate or permit for the site or route has been issued, 
 59.10  then the utility must certify to the board that the site or 
 59.11  route continues to meet the conditions upon which the 
 59.12  certificate of site compatibility or transmission line 
 59.13  construction permit was issued. 
 59.14     Sec. 3.  Minnesota Statutes 2000, section 116C.64, is 
 59.15  amended to read: 
 59.16     116C.64 [FAILURE TO ACT.] 
 59.17     If the board fails to act within the times specified in 
 59.18  section 116C.57, the applicant or any affected utility person 
 59.19  may seek an order of the district court requiring the board to 
 59.20  designate or refuse to designate a site or route. 
 59.21     Sec. 4.  Minnesota Statutes 2000, section 116C.645, is 
 59.22  amended to read: 
 59.23     116C.645 [REVOCATION OR SUSPENSION.] 
 59.24     A site certificate permit or construction route permit may 
 59.25  be revoked or suspended by the board after adequate notice of 
 59.26  the alleged grounds for revocation or suspension and a full and 
 59.27  fair hearing in which the affected utility has an opportunity to 
 59.28  confront any witness and respond to any evidence against it and 
 59.29  to present rebuttal or mitigating evidence upon a finding by the 
 59.30  board of: 
 59.31     (1) any false statement knowingly made in the application 
 59.32  or in accompanying statements or studies required of the 
 59.33  applicant, if a true statement would have warranted a change in 
 59.34  the board's findings; 
 59.35     (2) failure to comply with material conditions of the site 
 59.36  certificate or construction permit, or failure to maintain 
 60.1   health and safety standards; or 
 60.2      (3) any material violation of the provisions of sections 
 60.3   116C.51 to 116C.69, any rule promulgated pursuant thereto 
 60.4   adopted under these sections, or any order of the board. 
 60.5      Sec. 5.  Minnesota Statutes 2000, section 116C.65, is 
 60.6   amended to read: 
 60.7      116C.65 [JUDICIAL REVIEW.] 
 60.8      Any utility applicant, party, or person aggrieved by the 
 60.9   issuance of a certificate site or route permit or emergency 
 60.10  certificate of site compatibility or transmission line 
 60.11  construction permit from the board or a certification of 
 60.12  continuing suitability filed by a utility with the board or by a 
 60.13  final order in accordance with any rules promulgated adopted by 
 60.14  the board, may appeal to the court of appeals in accordance with 
 60.15  chapter 14.  The appeal shall must be filed within 60 days after 
 60.16  the publication in the State Register of notice of the issuance 
 60.17  of the certificate or permit by the board or certification filed 
 60.18  with the board or the filing of any final order by the board.  
 60.19     Sec. 6.  Minnesota Statutes 2000, section 116C.66, is 
 60.20  amended to read: 
 60.21     116C.66 [RULES.] 
 60.22     (a) The board, in order to give effect to the purposes of 
 60.23  sections 116C.51 to 116C.69, shall prior to July 1, 1978, may 
 60.24  adopt rules consistent with sections 116C.51 to 116C.69, 
 60.25  including promulgation adoption of site and route designation 
 60.26  criteria,; the description of the information to be furnished by 
 60.27  the utilities,; establishment of minimum guidelines for public 
 60.28  participation in the development, revision, and enforcement of 
 60.29  any rule, plan, or program established by the board,; procedures 
 60.30  for the revocation or suspension of a construction permit or a 
 60.31  certificate of site compatibility,; the procedure and timeliness 
 60.32  for proposing alternative routes and sites,; and route exemption 
 60.33  criteria and procedures. 
 60.34     No (b) A rule adopted by the board shall may not grant 
 60.35  priority to state-owned wildlife management areas over 
 60.36  agricultural lands in the designation of route-avoidance areas. 
 61.1      (c) The provisions of chapter 14 shall apply to the appeal 
 61.2   of rules adopted by the board to the same extent as it applies 
 61.3   to the review of rules adopted by any other agency of state 
 61.4   government. 
 61.5      (d) The chief administrative law judge shall, prior to 
 61.6   January 1, 1978, adopt procedural rules for public hearings 
 61.7   relating to the site and route designation process and to the 
 61.8   route exemption process.  The rules shall must attempt to 
 61.9   maximize citizen participation in these processes. 
 61.10     Sec. 7.  Minnesota Statutes 2000, section 116C.69, is 
 61.11  amended to read: 
 61.12     116C.69 [BIENNIAL REPORT; APPLICATION FEES; APPROPRIATION; 
 61.13  FUNDING.] 
 61.14     Subdivision 1.  [BIENNIAL REPORT.] Before November 15 of 
 61.15  each even-numbered year the board shall prepare and submit to 
 61.16  the legislature a report of its operations, activities, 
 61.17  findings, and recommendations concerning sections 116C.51 to 
 61.18  116C.69.  The report shall also contain information on the 
 61.19  board's biennial expenditures, its proposed budget for the 
 61.20  following biennium, and the amounts paid in certificate and 
 61.21  permit application fees pursuant to subdivisions 2 and 2a and in 
 61.22  assessments pursuant to subdivision 3 section 116C.69.  The 
 61.23  proposed budget for the following biennium shall be is subject 
 61.24  to legislative review. 
 61.25     Subd. 2.  [SITE APPLICATION FEE.] Every applicant for a 
 61.26  site certificate permit shall pay to the board a fee in an 
 61.27  amount equal to $500 for each $1,000,000 of production plant 
 61.28  investment in the proposed installation as defined in the 
 61.29  Federal Power Commission Uniform System of Accounts.  The board 
 61.30  shall specify the time and manner of payment of the fee.  If any 
 61.31  single payment requested by the board is in excess of 25 percent 
 61.32  of the total estimated fee, the board shall show that the excess 
 61.33  is reasonably necessary.  The applicant shall pay within 30 days 
 61.34  of notification any additional fees reasonably necessary for 
 61.35  completion of the site evaluation and designation process by the 
 61.36  board.  In no event shall The total fees required of the 
 62.1   applicant under this subdivision must never exceed an amount 
 62.2   equal to 0.001 of said the production plant investment (, which 
 62.3   equals $1,000 for each $1,000,000).  All money received pursuant 
 62.4   to under this subdivision shall must be deposited in a special 
 62.5   account.  Money in the account is appropriated to the board to 
 62.6   pay expenses incurred in processing applications 
 62.7   for certificates site permits in accordance with sections 
 62.8   116C.51 to 116C.69 and in the event, if the expenses are less 
 62.9   than the fee paid, to refund the excess to the applicant.  
 62.10     Subd. 2a.  [ROUTE APPLICATION FEE.] Every applicant for a 
 62.11  transmission line construction route permit shall pay to the 
 62.12  board a base fee of $35,000 plus a fee in an amount equal to 
 62.13  $1,000 per mile length of the longest proposed route.  The board 
 62.14  shall specify the time and manner of payment of the fee.  If any 
 62.15  single payment requested by the board is in excess of 25 percent 
 62.16  of the total estimated fee, the board shall show that the excess 
 62.17  is reasonably necessary.  In the event If the actual cost of 
 62.18  processing an application up to the board's final decision to 
 62.19  designate a route exceeds the above this fee schedule, the board 
 62.20  may assess the applicant any additional fees necessary to cover 
 62.21  the actual costs, not to exceed an amount equal to $500 per mile 
 62.22  length of the longest proposed route.  All money received 
 62.23  pursuant to under this subdivision shall must be deposited in a 
 62.24  special account.  Money in the account is appropriated to the 
 62.25  board to pay expenses incurred in processing applications for 
 62.26  construction route permits in accordance with sections 116C.51 
 62.27  to 116C.69 and in the event, if the expenses are less than the 
 62.28  fee paid, to refund the excess to the applicant.  
 62.29     Subd. 3.  [FUNDING; ASSESSMENT.] (a) The board shall 
 62.30  finance its base line studies, general environmental studies, 
 62.31  development of criteria, inventory preparation, monitoring of 
 62.32  conditions placed on site certificates and construction route 
 62.33  permits, and all other work, other than specific site and route 
 62.34  designation, from an assessment made quarterly, at least 30 days 
 62.35  before the start of each quarter, by the board against all 
 62.36  utilities with annual retail kilowatt-hour sales greater than 
 63.1   4,000,000 kilowatt-hours in the previous calendar year.  
 63.2      (b) Each share shall must be determined as follows: 
 63.3      (1) the ratio that the annual retail kilowatt-hour sales in 
 63.4   the state of each utility bears to the annual total retail 
 63.5   kilowatt-hour sales in the state of all these utilities, 
 63.6   multiplied by 0.667,; plus 
 63.7      (2) the ratio that the annual gross revenue from retail 
 63.8   kilowatt-hour sales in the state of each utility bears to the 
 63.9   annual total gross revenues from retail kilowatt-hour sales in 
 63.10  the state of all these utilities, multiplied by 0.333, as 
 63.11  determined by the board. 
 63.12     (c) The assessment shall must be credited to the special 
 63.13  revenue fund and shall be paid to the state treasury within 30 
 63.14  days after receipt of the bill, which shall constitute notice of 
 63.15  said the assessment and its demand of payment thereof. 
 63.16     (d) The total amount which that may be assessed to the 
 63.17  several utilities under the authority of this subdivision shall 
 63.18  may not exceed the sum of the annual budget of the board for 
 63.19  carrying out the purposes of this subdivision. 
 63.20     (e) The assessment for the second quarter of each fiscal 
 63.21  year shall must be adjusted to compensate for the amount by 
 63.22  which actual expenditures by the board for the preceding fiscal 
 63.23  year were more or less than the estimated expenditures 
 63.24  previously assessed. 
 63.25     Sec. 8.  Minnesota Statutes 2000, section 216B.03, is 
 63.26  amended to read: 
 63.27     216B.03 [REASONABLE RATE.] 
 63.28     (a) Every rate made, demanded, or received by any public 
 63.29  utility, or by any two or more public utilities jointly, shall 
 63.30  must be just and reasonable.  Rates shall must not be 
 63.31  unreasonably preferential, or unreasonably prejudicial or 
 63.32  discriminatory, but shall must be sufficient, equitable, and 
 63.33  consistent in application to a class of consumers.  To the 
 63.34  maximum reasonable extent, the commission shall set rates to 
 63.35  encourage energy conservation and renewable energy use and to 
 63.36  further the goals of sections 216B.164, 216B.241, 216B.2411, and 
 64.1   216C.05.  Any doubt as to reasonableness should be resolved in 
 64.2   favor of the consumer. 
 64.3      (b) For rate-making purposes a public utility may treat two 
 64.4   or more municipalities served by it as a single class wherever 
 64.5   the populations are comparable in size or the conditions of 
 64.6   service are similar.  
 64.7      Sec. 9.  Minnesota Statutes 2000, section 216B.16, 
 64.8   subdivision 1, is amended to read: 
 64.9      Subdivision 1.  [NOTICE.] Unless the commission otherwise 
 64.10  orders, no public utility shall change a rate which that has 
 64.11  been duly established under this chapter, except upon 60 days' 
 64.12  notice to the commission.  The notice shall must include 
 64.13  statements of facts, expert opinions, substantiating documents, 
 64.14  and exhibits, supporting the change requested, and state the 
 64.15  change proposed to be made in the rates then in force and the 
 64.16  time when the modified rates will go into effect.  If the filing 
 64.17  utility does not have an approved conservation improvement plan 
 64.18  on file with the department of public service, it shall also 
 64.19  include in its notice an energy conservation plan pursuant to 
 64.20  section 216B.241.  The filing utility shall give written notice, 
 64.21  as approved by the commission, of the proposed change to the 
 64.22  governing body of each municipality and county in the area 
 64.23  affected.  All proposed changes shall must be shown by filing 
 64.24  new schedules or shall be plainly indicated upon schedules on 
 64.25  file and in force at the time. 
 64.26     Sec. 10.  Minnesota Statutes 2000, section 216B.16, 
 64.27  subdivision 6b, is amended to read: 
 64.28     Subd. 6b.  [ENERGY CONSERVATION IMPROVEMENT.] (a) Except as 
 64.29  otherwise provided in this subdivision, all investments and 
 64.30  expenses of a public utility as defined in section 216B.241, 
 64.31  subdivision 1, paragraph (e), incurred in connection with energy 
 64.32  conservation improvements shall under either section 216B.241 or 
 64.33  216B.2411 must be recognized and included by the commission in 
 64.34  the determination of just and reasonable rates as if the 
 64.35  investments and expenses were directly made or incurred by the 
 64.36  utility in furnishing utility service. 
 65.1      (b) After December 31, 1999, investments and expenses for 
 65.2   energy conservation improvements shall must not be included by 
 65.3   the commission in the determination of just and reasonable 
 65.4   electric and gas rates for retail electric and gas service 
 65.5   provided to large electric customer facilities that have been 
 65.6   exempted by the commissioner of the department of public service 
 65.7   pursuant to section 216B.241, subdivision 1a, paragraph (b).  
 65.8   However, no a public utility shall may not be prevented from 
 65.9   recovering its investment in energy conservation improvements 
 65.10  from all customers that were made on or before December 31, 
 65.11  1999, in compliance with the requirements of section 216B.241.  
 65.12     (c) The commission may permit a public utility to file rate 
 65.13  schedules providing for annual recovery of the costs of energy 
 65.14  conservation improvements under either section 216B.241 or 
 65.15  216B.2411.  These rate schedules may be applicable to less than 
 65.16  all the customers in a class of retail customers if necessary to 
 65.17  reflect the differing minimum spending requirements of section 
 65.18  216B.241, subdivision 1a.  After December 31, 1999, the 
 65.19  commission shall allow a public utility, without requiring a 
 65.20  general rate filing under this section, to reduce the electric 
 65.21  and gas rates applicable to large electric customer facilities 
 65.22  that have been exempted by the commissioner of the department of 
 65.23  public service pursuant to section 216B.241, subdivision 1a, 
 65.24  paragraph (b), by an amount that reflects the elimination of 
 65.25  energy conservation improvement investments or expenditures for 
 65.26  those facilities required on or before December 31, 1999.  In 
 65.27  the event that If the commission has set electric or gas rates 
 65.28  based on the use of an accounting methodology that results in 
 65.29  the cost of conservation improvements being recovered from 
 65.30  utility customers over a period of years, the rate reduction may 
 65.31  occur in a series of steps to coincide with the recovery of 
 65.32  balances due to the utility for conservation improvements made 
 65.33  by the utility on or before December 31, 1999.  
 65.34     Sec. 11.  Minnesota Statutes 2000, section 216B.16, 
 65.35  subdivision 6c, is amended to read: 
 65.36     Subd. 6c.  [INCENTIVE PLAN FOR ENERGY CONSERVATION 
 66.1   IMPROVEMENT.] (a) The commission may order public utilities to 
 66.2   develop and submit for commission approval incentive plans that 
 66.3   describe the method of recovery and accounting for utility 
 66.4   conservation expenditures and savings under either section 
 66.5   216B.241 or 216B.2411.  In developing the incentive plans the 
 66.6   commission shall ensure the effective involvement of interested 
 66.7   parties. 
 66.8      (b) In approving incentive plans, the commission shall 
 66.9   consider: 
 66.10     (1) whether the plan is likely to increase utility 
 66.11  investment in cost-effective energy conservation; 
 66.12     (2) whether the plan is compatible with the interest of 
 66.13  utility ratepayers and other interested parties; 
 66.14     (3) whether the plan links the incentive to the utility's 
 66.15  performance in achieving cost-effective conservation; and 
 66.16     (4) whether the plan is in conflict with other provisions 
 66.17  of this chapter. 
 66.18     (c) The commission may set rates to encourage the vigorous 
 66.19  and effective implementation of utility conservation programs.  
 66.20  The commission may: 
 66.21     (1) increase or decrease any otherwise allowed rate of 
 66.22  return on net investment based upon the utility's skill, 
 66.23  efforts, and success in conserving energy; 
 66.24     (2) share between ratepayers and utilities the net savings 
 66.25  resulting from energy conservation programs to the extent 
 66.26  justified by the utility's skill, efforts, and success in 
 66.27  conserving energy; and 
 66.28     (3) compensate the utility for earnings lost as a result of 
 66.29  its conservation programs. 
 66.30     Sec. 12.  Minnesota Statutes 2000, section 216B.162, 
 66.31  subdivision 8, is amended to read: 
 66.32     Subd. 8.  [ENERGY EFFICIENCY IMPROVEMENT; EXPENSE 
 66.33  RECOVERY.] If the commission approves a competitive rate or the 
 66.34  parties agree to a modified rate, the commission may require the 
 66.35  electric utility to provide the customer with an energy audit 
 66.36  and assist in implementing cost-effective energy efficiency 
 67.1   improvements to assure that the customer's use of electricity is 
 67.2   efficient.  An investment in cost-effective energy conservation 
 67.3   improvements required under this section must be treated as an 
 67.4   energy conservation improvement program and included in 
 67.5   the department's determination of significant investments under 
 67.6   section 216B.241 or 216B.2411.  The utility shall recover energy 
 67.7   conservation improvement expenses in a rate proceeding under 
 67.8   section 216B.16 or 216B.17 in the same manner as the commission 
 67.9   authorizes for the recovery of conservation expenditures made 
 67.10  under section 216B.241 or 216B.2411. 
 67.11     Sec. 13.  Minnesota Statutes 2000, section 216B.1621, 
 67.12  subdivision 2, is amended to read: 
 67.13     Subd. 2.  [COMMISSION APPROVAL.] (a) The commission shall 
 67.14  approve an agreement under this section upon finding that: 
 67.15     (1) the proposed electric service power generation facility 
 67.16  could reasonably be expected to qualify for a market value 
 67.17  exclusion under section 272.0211; 
 67.18     (2) the public utility has a contractual option to purchase 
 67.19  electric power from the proposed facility; and 
 67.20     (3) the public utility can use the output from the proposed 
 67.21  facility to meet its future need for power as demonstrated in 
 67.22  the most recent resource plan filed with and approved by the 
 67.23  commission under section 216B.2422. 
 67.24     (b) Sections 216B.03, 216B.05, 216B.06, 216B.07, 216B.16, 
 67.25  216B.162, and 216B.23 do not apply to an agreement under this 
 67.26  section. 
 67.27     Sec. 14.  Minnesota Statutes 2000, section 216B.164, 
 67.28  subdivision 4, is amended to read: 
 67.29     Subd. 4.  [PURCHASES; WHEELING; COSTS.] (a) Except as 
 67.30  otherwise provided in paragraph (c), this subdivision shall 
 67.31  apply to all qualifying facilities having 40-kilowatt capacity 
 67.32  or more as well as qualifying facilities as defined in 
 67.33  subdivision 3 which elect to be governed by its provisions.  
 67.34     (b) The utility to which the qualifying facility is 
 67.35  interconnected shall purchase all energy and capacity made 
 67.36  available by the qualifying facility.  The qualifying facility 
 68.1   shall be paid the utility's full avoided capacity and energy 
 68.2   costs as negotiated by the parties, as set by the commission, or 
 68.3   as determined through competitive bidding approved by the 
 68.4   commission.  The full avoided capacity and energy costs to be 
 68.5   paid a qualifying facility that generates electric power by 
 68.6   means of a renewable energy source are the utility's least cost 
 68.7   renewable energy facility or the bid of a competing supplier of 
 68.8   a least cost renewable energy facility, whichever is lower, 
 68.9   unless the commission's resource plan order, under section 
 68.10  216B.2422, subdivision 2, provides commission determines that 
 68.11  the use of a renewable resource to meet the identified capacity 
 68.12  need is not in the public interest.  
 68.13     (c) For all qualifying facilities having 30-kilowatt 
 68.14  capacity or more, the utility shall, at the qualifying 
 68.15  facility's or the utility's request, provide wheeling or 
 68.16  exchange agreements wherever practicable to sell the qualifying 
 68.17  facility's output to any other Minnesota utility having 
 68.18  generation expansion anticipated or planned for the ensuing ten 
 68.19  years.  The commission shall establish the methods and 
 68.20  procedures to insure that except for reasonable wheeling charges 
 68.21  and line losses, the qualifying facility receives the full 
 68.22  avoided energy and capacity costs of the utility ultimately 
 68.23  receiving the output.  
 68.24     (d) The commission shall set rates for electricity 
 68.25  generated by renewable energy. 
 68.26     Sec. 15.  Minnesota Statutes 2000, section 216B.2423, 
 68.27  subdivision 2, is amended to read: 
 68.28     Subd. 2.  [RESOURCE PLANNING MANDATE.] The public utilities 
 68.29  commission shall order a public utility subject to subdivision 
 68.30  1, to construct and operate, purchase, or contract to purchase 
 68.31  an additional 400 megawatts of electric energy installed 
 68.32  capacity generated by wind energy conversion systems by December 
 68.33  31, 2002, subject to any resource planning and least cost 
 68.34  planning requirements in section 216B.2422. 
 68.35     Sec. 16.  Minnesota Statutes 2000, section 216C.17, 
 68.36  subdivision 3, is amended to read: 
 69.1      Subd. 3.  [DUPLICATION.] The commissioner shall, to the 
 69.2   maximum extent feasible, provide that forecasts required under 
 69.3   this section be consistent with material required by other state 
 69.4   and federal agencies in order to prevent unnecessary 
 69.5   duplication.  Electric utilities submitting advance forecasts as 
 69.6   part of an integrated resource plan filed pursuant to section 
 69.7   216B.2422 and public utilities commission rules are excluded 
 69.8   from the annual reporting requirement in subdivision 2. 
 69.9      Sec. 17.  [INSTRUCTION TO REVISOR.] 
 69.10     The revisor of statutes shall renumber Minnesota Statutes, 
 69.11  section 116C.69, subdivision 1, as Minnesota Statutes, section 
 69.12  116C.681. 
 69.13                             ARTICLE 6
 69.14                      MISCELLANEOUS PROVISIONS
 69.15     Section 1.  Minnesota Statutes 2000, section 216A.03, 
 69.16  subdivision 3a, is amended to read: 
 69.17     Subd. 3a.  [POWERS AND DUTIES OF CHAIR.] The chair shall be 
 69.18  is the principal executive officer of the commission and shall 
 69.19  preside at meetings of the commission.  The responsibilities of 
 69.20  the chair shall organize include: 
 69.21     (1) organizing the work of the commission and may make; 
 69.22     (2) making assignments to commission members, appoint 
 69.23  committees and give as appropriate; 
 69.24     (3) appointing subcommittees; 
 69.25     (4) giving direction to the commission staff through the 
 69.26  executive secretary subject to the approval of the commission.; 
 69.27     (5) supervising the work of the executive secretary; and 
 69.28     (6) in coordination with the executive secretary, 
 69.29  participating in employment and termination decisions, including 
 69.30  representing the commission in grievance proceedings; addressing 
 69.31  employee complaints and grievances; developing and implementing 
 69.32  the agency budget; testifying before legislative committees and 
 69.33  working with legislators as requested; determining agency-wide 
 69.34  training needs and initiatives; implementing computer technology 
 69.35  updates; administering and implementing relations with the 
 69.36  department of commerce, the office of the attorney general, and 
 70.1   other agencies; and developing and implementing strategies for 
 70.2   the commission to adapt to rapid changes in the industries the 
 70.3   commission oversees. 
 70.4      Sec. 2.  Minnesota Statutes 2000, section 216B.095, is 
 70.5   amended to read: 
 70.6      216B.095 [DISCONNECTION DURING COLD WEATHER.] 
 70.7      The commission shall amend its rules governing 
 70.8   disconnection of residential utility customers who are unable to 
 70.9   pay for utility service during cold weather to include the 
 70.10  following: 
 70.11     (1) coverage of customers whose household income is less 
 70.12  than 185 percent of the federal poverty level 50 percent of the 
 70.13  state median income; 
 70.14     (2) a requirement that a customer who pays the utility at 
 70.15  least ten percent of the customer's income or the full amount of 
 70.16  the utility bill, whichever is less, in a cold weather month 
 70.17  cannot be disconnected during that month; 
 70.18     (3) that the ten percent figure in clause (2) must be 
 70.19  prorated between energy providers proportionate to each 
 70.20  provider's share of the customer's total energy costs where the 
 70.21  customer receives service from more than one provider; 
 70.22     (4) that a customer's household income does not include any 
 70.23  amount received for energy assistance; 
 70.24     (5) (4) verification of income by the local energy 
 70.25  assistance provider or the utility, unless the customer is 
 70.26  automatically eligible for protection against disconnection as a 
 70.27  recipient of any form of public assistance, including energy 
 70.28  assistance, that uses income eligibility in an amount at or 
 70.29  below the income eligibility in clause (1); and 
 70.30     (6) (5) a requirement that the customer receive, from the 
 70.31  local energy assistance provider or other entity, budget 
 70.32  counseling and referral referrals to energy assistance programs, 
 70.33  weatherization, conservation, or other programs likely to reduce 
 70.34  the customer's consumption of energy bills; 
 70.35     (6) a requirement that customers who have demonstrated an 
 70.36  inability to pay on forms for such purposes provided by the 
 71.1   utility, and who make reasonably timely payments to the utility 
 71.2   under a payment plan that considers the financial resources of 
 71.3   the household, cannot be disconnected from utility services from 
 71.4   October 15 to April 15.  A customer who is receiving energy 
 71.5   assistance is deemed to have demonstrated an inability to pay. 
 71.6   For the purpose of clause (2), the "customer's income" means the 
 71.7   actual monthly income of the customer except for a customer who 
 71.8   is normally employed only on a seasonal basis and whose annual 
 71.9   income is over 135 percent of the federal poverty level, in 
 71.10  which case the customer's income is or the average monthly 
 71.11  income of the customer computed on an annual calendar year 
 71.12  basis, whichever is less, and does not include any amount 
 71.13  received for energy assistance. 
 71.14     Sec. 3.  Minnesota Statutes 2000, section 216B.097, 
 71.15  subdivision 1, is amended to read: 
 71.16     Subdivision 1.  [APPLICATION; NOTICE TO RESIDENTIAL 
 71.17  CUSTOMER.] (a) A municipal utility or a cooperative electric 
 71.18  association must not disconnect the utility service of a 
 71.19  residential customer during the period between October 15 and 
 71.20  April 15 if the disconnection affects the primary heat source 
 71.21  for the residential unit when the following conditions are met: 
 71.22     (1) the disconnection would occur during the period between 
 71.23  October 15 and April 15; 
 71.24     (2) (1) the customer has declared inability to pay on forms 
 71.25  provided by the utility.  For the purpose of this clause, a 
 71.26  customer that is receiving energy assistance is deemed to have 
 71.27  demonstrated an inability to pay; 
 71.28     (3) (2) the household income of the customer is less than 
 71.29  185 percent of the federal poverty level, as documented by the 
 71.30  customer to the utility; and 50 percent of the state median 
 71.31  income; 
 71.32     (3) verification of income may be conducted by the local 
 71.33  energy assistance provider or the utility, unless the customer 
 71.34  is automatically eligible for protection against disconnection 
 71.35  as a recipient of any form of public assistance, including 
 71.36  energy assistance, that uses income eligibility in an amount at 
 72.1   or below the income eligibility in clause (2); 
 72.2      (4) the customer's a customer whose account is current for 
 72.3   the billing period immediately prior to October 15 or the 
 72.4   customer has entered who, at any time, enters into a payment 
 72.5   schedule that considers the financial resources of the household 
 72.6   and is reasonably current with payments under the schedule; and 
 72.7      (5) the customer receives referrals to energy assistance 
 72.8   programs, and weatherization, conservation, or other programs to 
 72.9   reduce the customer's energy bills. 
 72.10     (b) A municipal utility or a cooperative electric 
 72.11  association must, between August 15 and October 15 of each year, 
 72.12  notify all residential customers of the provisions of this 
 72.13  section. 
 72.14     Sec. 4.  [216B.098] [CUSTOMER PROTECTIONS.] 
 72.15     Subdivision 1.  [APPLICABILITY.] This section applies to 
 72.16  residential customers of public utilities, municipal utilities, 
 72.17  and cooperative electric associations. 
 72.18     Subd. 2.  [BUDGET BILLING PLANS.] A utility shall offer a 
 72.19  customer a budget billing plan for payment of charges for 
 72.20  service, including adequate notice to customers prior to 
 72.21  changing budget payment amounts.  Municipal utilities having 
 72.22  3,000 or fewer customers are exempt from this requirement.  
 72.23  Municipal utilities having more than 3,000 customers shall 
 72.24  implement this requirement within two years of the effective 
 72.25  date of this chapter. 
 72.26     Subd. 3.  [PAYMENT AGREEMENTS.] A utility shall offer a 
 72.27  payment agreement for the payment of arrears. 
 72.28     Subd. 4.  [UNDERCHARGES.] A utility shall offer a payment 
 72.29  agreement to customers who have been undercharged if no culpable 
 72.30  conduct by the customer or resident of the customer's household 
 72.31  caused the undercharge.  The agreement must cover a period equal 
 72.32  to the time over which the undercharge occurred.  No interest or 
 72.33  delinquency fee may be charged under this agreement. 
 72.34     Subd. 5.  [MEDICALLY NECESSARY EQUIPMENT.] A utility shall 
 72.35  reconnect or continue service to a customer's residence where a 
 72.36  medical emergency exists or where medical equipment requiring 
 73.1   electricity is necessary to sustain life is in use, provided 
 73.2   that the utility receives from a medical doctor written 
 73.3   certification, or initial certification by telephone and written 
 73.4   certification within five business days, that failure to 
 73.5   reconnect or continue service will impair or threaten the health 
 73.6   or safety of a resident of the customer's household.  The 
 73.7   customer must enter into a payment agreement. 
 73.8      Subd. 6.  [COMMISSION AUTHORITY.] The commission, or staff 
 73.9   designated by the commission, has the authority to order 
 73.10  resolutions of disputes involving alleged violations of this 
 73.11  chapter or any other disputes involving public utilities coming 
 73.12  within its jurisdiction. 
 73.13     Sec. 5.  Minnesota Statutes 2000, section 216B.16, 
 73.14  subdivision 15, is amended to read: 
 73.15     Subd. 15.  [LOW-INCOME RATE PROGRAMS; REPORT.] (a) The 
 73.16  commission may consider ability to pay as a factor in setting 
 73.17  utility rates and may establish programs for low-income 
 73.18  residential ratepayers in order to ensure affordable, reliable, 
 73.19  and continuous service to low-income utility customers.  The 
 73.20  commission shall order a pilot program for at least one 
 73.21  utility.  In ordering pilot programs, the commission shall 
 73.22  consider the following: 
 73.23     (1) the potential for low-income programs to provide 
 73.24  savings to the utility for all collection costs including but 
 73.25  not limited to:  costs of disconnecting and reconnecting 
 73.26  residential ratepayers' service, all activities related to the 
 73.27  utilities' attempt to collect past due bills, utility working 
 73.28  capital costs, and any other administrative costs related to 
 73.29  inability to pay programs and initiatives; 
 73.30     (2) the potential for leveraging federal low-income energy 
 73.31  dollars to the state; and 
 73.32     (3) the impact of energy costs as a percentage of the total 
 73.33  income of a low-income residential customer. 
 73.34     (b) In determining the structure of the pilot utility 
 73.35  program, the commission shall: 
 73.36     (1) consult with advocates for and representatives of 
 74.1   low-income utility customers, administrators of energy 
 74.2   assistance and conservation programs, and utility 
 74.3   representatives; 
 74.4      (2) coordinate eligibility for the program with the state 
 74.5   and federal energy assistance program and low-income residential 
 74.6   energy programs, including weatherization programs; and 
 74.7      (3) evaluate comprehensive low-income programs offered by 
 74.8   utilities in other states. 
 74.9      (c) The commission shall implement at least one pilot 
 74.10  project by January 1, 1995, and shall allow a utility required 
 74.11  to implement a pilot project to recover the net costs of the 
 74.12  project in the utility's rates. 
 74.13     (d) The commission, in conjunction with the commissioner of 
 74.14  the department of public service and the commissioner of 
 74.15  economic security, shall review low-income rate programs and 
 74.16  shall report to the legislature by January 1, 1998.  The report 
 74.17  must include: 
 74.18     (1) the increase in federal energy assistance money 
 74.19  leveraged by the state as a result of this program; 
 74.20     (2) the effect of the program on low-income customer's 
 74.21  ability to pay energy costs; 
 74.22     (3) the effect of the program on utility customer bad debt 
 74.23  and arrearages; 
 74.24     (4) the effect of the program on the costs and numbers of 
 74.25  utility disconnections and reconnections and other costs 
 74.26  incurred by the utility in association with inability to pay 
 74.27  programs; 
 74.28     (5) the ability of the utility to recover the costs of the 
 74.29  low-income program without a general rate change; 
 74.30     (6) how other ratepayers have been affected by this 
 74.31  program; 
 74.32     (7) recommendations for continuing, eliminating, or 
 74.33  expanding the low-income pilot program; and 
 74.34     (8) how general revenue funds may be utilized in 
 74.35  conjunction with low-income programs. 
 74.36     (b) The purpose of the low-income programs is to lower the 
 75.1   percentage of income that low-income households devote to energy 
 75.2   bills, to increase customer payments, and to lower utility costs 
 75.3   associated with customer account collection activities.  In 
 75.4   ordering low-income programs, the commission may require 
 75.5   utilities to file program evaluations, including the effect of 
 75.6   the program on participant household energy burdens, the 
 75.7   coordination of other available low-income bill payment and 
 75.8   conservation resources, the effect of the program on service 
 75.9   disconnections, and the effect of the program on customer 
 75.10  payment behavior, utility collection costs, arrearages, and bad 
 75.11  debt. 
 75.12     Sec. 6.  [216B.79] [PREVENTATIVE MAINTENANCE.] 
 75.13     (a) The commission has the authority to ensure that public 
 75.14  utilities are making adequate infrastructure investments and 
 75.15  undertaking sufficient preventative maintenance with regard to 
 75.16  such facilities.  
 75.17     (b) The commission may make appropriate adjustments in a 
 75.18  utility's rates, or make a recommendation to the Federal Energy 
 75.19  Regulatory Commission to make an appropriate adjustment in a 
 75.20  utility's allowed rate of return on those utilities' 
 75.21  transmission facilities, to provide incentive and offset the 
 75.22  costs of new energy infrastructure facility construction. 
 75.23     Sec. 7.  Minnesota Statutes 2000, section 216C.41, is 
 75.24  amended to read: 
 75.25     216C.41 [RENEWABLE ENERGY PRODUCTION INCENTIVE.] 
 75.26     Subdivision 1.  [DEFINITIONS.] (a) The definitions in this 
 75.27  subdivision apply to this section. 
 75.28     (b) "Qualified hydroelectric facility" means a 
 75.29  hydroelectric generating facility in this state that: 
 75.30     (1) is located at the site of a dam, if the dam was in 
 75.31  existence as of March 31, 1994; and 
 75.32     (2) either (i) begins generating electricity after July 1, 
 75.33  1994; or (ii) is generating electricity as of June 30, 2001, and 
 75.34  undergoes substantial refurbishing after that date, to be 
 75.35  completed by December 31, 2005. 
 75.36     (c) "Qualified wind energy conversion facility" means a 
 76.1   wind energy conversion system that: 
 76.2      (1) produces two megawatts or less of electricity as 
 76.3   measured by nameplate rating and begins generating electricity 
 76.4   after June 30, 1997, and before July 1, 1999; 
 76.5      (2) begins generating electricity after June 30, 1999, 
 76.6   produces two megawatts or less of electricity as measured by 
 76.7   nameplate rating, and is: 
 76.8      (i) located within one county and owned by a natural person 
 76.9   who owns the land where the facility is sited; 
 76.10     (ii) owned or operated, in whole or in part, but in no 
 76.11  event less than 51 percent by a one or more Minnesota small 
 76.12  business businesses as defined in section 645.445; 
 76.13     (iii) owned by a nonprofit organization; or 
 76.14     (iv) owned by a tribal council if the facility is located 
 76.15  within the boundaries of the reservation; or 
 76.16     (3) begins generating electricity after June 30, 1999, 
 76.17  produces seven megawatts or less of electricity as measured by 
 76.18  nameplate rating, and: 
 76.19     (i) is owned by a cooperative organized under chapter 308A; 
 76.20  and 
 76.21     (ii) all shares and membership in the cooperative are held 
 76.22  by natural persons or estates, at least 51 percent of whom 
 76.23  reside in a county or contiguous to a county where the wind 
 76.24  energy production facilities of the cooperative are located. 
 76.25     Subd. 2.  [INCENTIVE PAYMENT.] (a) Incentive payments shall 
 76.26  be made according to this section to the owner or operator of a 
 76.27  qualified hydropower facility or qualified wind energy 
 76.28  conversion facility for electric energy generated and sold by 
 76.29  the facility or, except as provided in paragraph (b) for a 
 76.30  publicly owned hydropower facility, for electric energy that is 
 76.31  generated by the facility and used by the owner of the facility 
 76.32  outside the facility.  
 76.33     (b) For a facility that is publicly owned and in need of 
 76.34  substantial refurbishment and repair, the incentive payment 
 76.35  shall be made to the public owner of the facility to finance 
 76.36  structural repairs and replacement of structural components. 
 77.1      (c) Payment may only be made upon receipt by the 
 77.2   commissioner of finance of an incentive payment application that 
 77.3   establishes that the applicant is eligible to receive an 
 77.4   incentive payment and that satisfies other requirements the 
 77.5   commissioner deems necessary.  The application shall be in a 
 77.6   form and submitted at a time the commissioner establishes.  
 77.7   There is annually appropriated from the general fund sums 
 77.8   sufficient to make the payments required under this section.  
 77.9      Subd. 3.  [ELIGIBILITY WINDOW.] Payments may be made under 
 77.10  this section only for electricity generated: 
 77.11     (1) from a qualified hydroelectric facility that is 
 77.12  operational and generating electricity before December 31, 2001, 
 77.13  or that undergoes substantial refurbishing after June 30, 2001, 
 77.14  to be completed by December 31, 2005; or 
 77.15     (2) from a qualified wind energy conversion facility that 
 77.16  is operational and generating electricity before January 1, 2005.
 77.17     Subd. 4.  [PAYMENT PERIOD.] A facility may receive payments 
 77.18  under this section for a ten-year period.  No payment under this 
 77.19  section may be made for electricity generated: 
 77.20     (1) by a qualified hydroelectric facility after December 
 77.21  31, 2010, or December 31, 2015, if the facility undergoes 
 77.22  substantial refurbishing after June 30, 2001; or 
 77.23     (2) by a qualified wind energy conversion facility after 
 77.24  December 31, 2015.  
 77.25     The payment period begins and runs consecutively from the 
 77.26  first year in which electricity generated from the facility is 
 77.27  eligible for incentive payment. 
 77.28     Subd. 5.  [AMOUNT OF PAYMENT.] (a) An incentive payment is 
 77.29  based on the number of kilowatt hours of electricity generated. 
 77.30  The amount of the payment is 1.5 cents per kilowatt hour.  For 
 77.31  electricity generated by qualified wind energy conversion 
 77.32  facilities, the incentive payment under this section is limited 
 77.33  to no more than 100 megawatts of nameplate capacity.  During any 
 77.34  period in which qualifying claims for incentive payments exceed 
 77.35  100 megawatts of nameplate capacity, the payments must be made 
 77.36  to producers in the order in which the production capacity was 
 78.1   brought into production.  
 78.2      (b) Beginning January 1, 2002, a qualified wind energy 
 78.3   conversion facility defined under subdivision 1, paragraph (c), 
 78.4   clause (1), (2), or (3), may not be located within five miles of 
 78.5   another qualified wind energy conversion facility constructed 
 78.6   within the same calendar year and owned by the same person.  For 
 78.7   the purposes of this paragraph, the department shall determine 
 78.8   that the same person owns two qualified wind energy conversion 
 78.9   facilities when the underlying ownership structure contains 
 78.10  similar persons or entities, other than a person or entity that 
 78.11  provides equity financing, even if the ownership shares differ 
 78.12  between the facilities. 
 78.13     Subd. 6.  [OWNERSHIP; FINANCING; CURE.] (a) For the 
 78.14  purposes of subdivision 1, paragraph (c), clause (2), a wind 
 78.15  energy conversion facility qualifies if it is owned at least 51 
 78.16  percent by one or more of any combination of the entities listed 
 78.17  in that clause. 
 78.18     (b) A subsequent owner of a qualified facility may continue 
 78.19  to receive the incentive payment for the duration of the 
 78.20  original payment period if the subsequent owner qualifies for 
 78.21  the incentive under subdivision 1. 
 78.22     (c) Nothing in this section may be construed to deny 
 78.23  incentive payment to an otherwise qualified facility that has 
 78.24  obtained debt or equity financing for construction or operation 
 78.25  as long as the ownership requirements of subdivision 1 and this 
 78.26  subdivision are met.  If, during the incentive payment period 
 78.27  for a qualified facility, the owner of the facility is in 
 78.28  default of a lending agreement and the lender takes possession 
 78.29  of and operates the facility and makes reasonable efforts to 
 78.30  transfer ownership of the facility to an entity other than the 
 78.31  lender, the lender may continue to receive the incentive payment 
 78.32  for electricity generated and sold by the facility for a period 
 78.33  not to exceed 18 months.  A lender who takes possession of a 
 78.34  facility shall notify the commissioner immediately on taking 
 78.35  possession and, at least quarterly, document efforts to transfer 
 78.36  ownership of the facility. 
 79.1      (d) If, during the incentive payment period, a qualified 
 79.2   facility loses the right to receive the incentive because of 
 79.3   changes in ownership, the facility may regain the right to 
 79.4   receive the incentive upon cure of the ownership structure that 
 79.5   resulted in the loss of eligibility and may reapply for the 
 79.6   incentive, but in no case may the payment period be extended 
 79.7   beyond the original ten-year limit. 
 79.8      (e) A subsequent or requalifying owner under paragraph (b)  
 79.9   or (d) retains the facility's original priority order for 
 79.10  incentive payments as long as the ownership structure 
 79.11  requalifies within two years from the date the facility became 
 79.12  unqualified or two years from the date a lender takes possession 
 79.13  of the facility. 
 79.14     Sec. 8.  [REPEALER.] 
 79.15     (a) Minnesota Statutes 2000, sections 216B.241, subdivision 
 79.16  1c, and 216C.18, are repealed. 
 79.17     (b) Minnesota Statutes 2000, section 216B.2422, 
 79.18  subdivisions 2 and 6, are repealed September 1, 2002. 
 79.19     Sec. 9.  [EFFECTIVE DATE.] 
 79.20     Articles 3 to 6 are effective the day following final 
 79.21  enactment, except that those provisions referring or relating to 
 79.22  article 1, section 2 or 3, the independent reliability 
 79.23  administrator or the state reliability plan, are effective July 
 79.24  1, 2002. 
 79.25                             ARTICLE 7
 79.26                    SAFETY AND SERVICE STANDARDS
 79.27     Section 1.  [216B.81] [DEFINITIONS.] 
 79.28     Subdivision 1.  [SCOPE.] The terms used in this article 
 79.29  have the meanings given them in this section. 
 79.30     Subd. 2.  [AVERAGE NUMBER OF CUSTOMERS SERVED.] "Average 
 79.31  number of customers served" means the number of active, metered, 
 79.32  customer accounts available in a utility's 
 79.33  interruption-reporting database on the day that an interruption 
 79.34  occurs. 
 79.35     Subd. 3.  [CIRCUIT.] "Circuit" means a set of conductors 
 79.36  serving customer loads that are capable of being separated from 
 80.1   the serving substation automatically by a recloser, fuse, 
 80.2   sectionalizing equipment, and other devices. 
 80.3      Subd. 4.  [COMPONENT.] "Component" means a piece of 
 80.4   equipment, a line, a section of line, or a group of items that 
 80.5   is an entity for purposes of reporting, analyzing, and 
 80.6   predicting interruptions. 
 80.7      Subd. 5.  [CUSTOMER.] "Customer" means a contiguous 
 80.8   electrical service location, regardless of the number of meters 
 80.9   at the location. 
 80.10     Subd. 6.  [CUSTOMER INTERRUPTION.] "Customer interruption" 
 80.11  means the loss of service due to a forced outage for more than 
 80.12  five minutes, for one or more customers, which is the result of 
 80.13  one or more component failures. 
 80.14     Subd. 7.  [CUSTOMERS' INTERRUPTIONS CAUSED BY POWER 
 80.15  RESTORATION PROCESS.] "Customers' interruptions caused by power 
 80.16  restoration process" means when customers lose power as a result 
 80.17  of the process of restoring power.  The duration of these 
 80.18  outages is included in the customer-minutes of interruption.  
 80.19  Only the customers affected by the power restoration outages 
 80.20  that were not affected by the original outage are added to the 
 80.21  number of customer interruptions.  
 80.22     Subd. 8.  [CUSTOMER-MINUTES OF 
 80.23  INTERRUPTION.] "Customer-minutes of interruption" means the 
 80.24  number of minutes of forced outage duration multiplied by the 
 80.25  number of customers affected. 
 80.26     Subd. 9.  [ELECTRIC DISTRIBUTION LINE.] "Electric 
 80.27  distribution line" means circuits operating at less than 40,000 
 80.28  volts. 
 80.29     Subd. 10.  [FORCED OUTAGE.] "Forced outage" means an outage 
 80.30  that cannot be deferred. 
 80.31     Subd. 11.  [MAJOR CATASTROPHIC EVENTS.] "Major catastrophic 
 80.32  events" means events that are beyond the utility's control that 
 80.33  result in widespread system damages causing customer 
 80.34  interruptions that affect at least ten percent of the customers 
 80.35  in the system or in an operating area or that result in 
 80.36  customers being without electric service for durations of at 
 81.1   least 24 hours. 
 81.2      Subd. 12.  [MAJOR STORM.] "Major storm" means a period of 
 81.3   severe adverse weather resulting in widespread system damage 
 81.4   causing customer interruptions that affect at least ten percent 
 81.5   of the customers on the system or in an operating area or that 
 81.6   result in customers being without electric service for durations 
 81.7   of at least 24 hours. 
 81.8      Subd. 13.  [MOMENTARY INTERRUPTION.] "Momentary 
 81.9   interruption" means an interruption of electric service with a 
 81.10  duration shorter than the time necessary to be classified as a 
 81.11  customer interruption. 
 81.12     Subd. 14.  [OPERATING AREA.] "Operating area" means a 
 81.13  geographical subdivision of each electric utility's service 
 81.14  territory that functions under the direction of a company office 
 81.15  and may be used for reporting interruptions under this article.  
 81.16  These areas may also be referred to as regions, divisions, or 
 81.17  districts. 
 81.18     Subd. 15.  [OUTAGE.] "Outage" means the failure of a power 
 81.19  system component that results in one or more customer 
 81.20  interruptions. 
 81.21     Subd. 16.  [OUTAGE DURATION.] "Outage duration" means the 
 81.22  one minute or greater period from the initiation of an 
 81.23  interruption to a customer until service has been restored to 
 81.24  that customer. 
 81.25     Subd. 17.  [PARTIAL CIRCUIT OUTAGE CUSTOMER 
 81.26  COUNT.] "Partial circuit outage customer count" means when only 
 81.27  part of a circuit experiences an outage, the number of customers 
 81.28  affected is estimated, unless an actual count is available.  
 81.29  When power is partially restored, the number of customers 
 81.30  restored is also estimated.  Most utilities use estimates based 
 81.31  on the portion of the circuit restored. 
 81.32     Subd. 18.  [PLANNED OUTAGES.] "Planned outages" means those 
 81.33  outages scheduled by the utility. These interruptions are 
 81.34  sometimes necessary to connect new customers or perform 
 81.35  maintenance activities safely.  They must not be included in the 
 81.36  calculation of reliability indexes. 
 82.1      Subd. 19.  [RELIABILITY.] "Reliability" means the degree to 
 82.2   which electric service is supplied without interruption. 
 82.3      Subd. 20.  [RELIABILITY INDEXES.] "Reliability indexes" 
 82.4   include the following performance indices for measuring 
 82.5   frequency and duration of service interruptions: 
 82.6      (a) The system average interruption frequency index is the 
 82.7   average number of interruptions per customer per year.  It is 
 82.8   determined by dividing the total annual number of customer 
 82.9   interruptions by the average number of customers served during 
 82.10  the year. 
 82.11     (b) The system average interruption duration index is the 
 82.12  average customer-minutes of interruption per customer.  It is 
 82.13  determined by dividing the annual sum of customer-minutes of 
 82.14  interruption by the average number of customers served during 
 82.15  the year. 
 82.16     (c) The customer average interruption duration index is the 
 82.17  average customer-minutes of interruption per customer 
 82.18  interruption.  It approximates the average length of time 
 82.19  required to complete service restoration.  It is determined by 
 82.20  dividing the annual sum of all customer-minutes of interruption 
 82.21  durations by the annual number of customer interruptions. 
 82.22     Sec. 2.  [216B.82] [RECORDING SERVICE INTERRUPTION 
 82.23  INDEXES.] 
 82.24     Subdivision 1.  [SYSTEM INTERRUPTION DATA.] Each electric 
 82.25  utility with 10,000 retail customers or more shall keep a record 
 82.26  of the necessary interruption data and calculate the system 
 82.27  average interruption frequency index, system average 
 82.28  interruption duration index, and customer average interruption 
 82.29  duration index of its system, and of each operating area, if 
 82.30  applicable, at the end of each calendar year for the previous 
 82.31  12-month period. 
 82.32     Subd. 2.  [CIRCUIT INTERRUPTION DATA.] Unless a utility 
 82.33  uses alternative criteria as provided in section 216B.83, 
 82.34  subdivision 2, paragraph (d), each utility also shall, at the 
 82.35  end of each calendar year, calculate the system average 
 82.36  interruption frequency index, system average interruption 
 83.1   duration index, and customer average interruption duration index 
 83.2   for each circuit in each operating area.  Each circuit in each 
 83.3   operating area must then be listed in order separately according 
 83.4   to its system average interruption frequency index, its system 
 83.5   average interruption duration index, and its customer average 
 83.6   interruption duration index, beginning with the highest values 
 83.7   for each index. 
 83.8      Sec. 3.  [216B.83] [ANNUAL REPORT.] 
 83.9      Subdivision 1.  [SUMMARY REPORT GENERALLY.] Beginning on 
 83.10  July 1, 2002, and by July 1 of every year thereafter, each 
 83.11  electric utility with 10,000 retail customers or more shall file 
 83.12  with the commission, or in the case of a cooperative electric 
 83.13  association or municipal utility, with the local governing body 
 83.14  of the utility or association a report summarizing various 
 83.15  measures of reliability.  The form of the report is subject to 
 83.16  review and comment by the commission staff.  Names and numbers 
 83.17  used to identify operating areas or individual circuits may 
 83.18  conform to the utility's practice, but should allow ready 
 83.19  identification of the geographic location or the general area 
 83.20  served.  Electronic recording and reporting of the required data 
 83.21  and information is encouraged.  
 83.22     Subd. 2.  [INFORMATION REQUIRED.] (a) The report must 
 83.23  include at least the information described in paragraphs (b) to 
 83.24  (h). 
 83.25     (b) The report must provide an overall assessment of the 
 83.26  reliability of performance including the aggregate system 
 83.27  average interruption frequency index, system average 
 83.28  interruption duration index, and customer average interruption 
 83.29  duration index by system and each operating area, as applicable. 
 83.30     (c) The report must include a list of the worst performing 
 83.31  circuits based on system average interruption frequency index, 
 83.32  system average interruption duration index, and customer average 
 83.33  interruption duration index for the calendar year.  This portion 
 83.34  of the report must describe the actions that the utility has 
 83.35  taken or will take to remedy the conditions responsible for each 
 83.36  listed circuit's unacceptable performance.  The actions taken or 
 84.1   planned should be briefly described.  Target dates for 
 84.2   corrective actions must be included in the report.  When the 
 84.3   utility determines that actions on its part are unwarranted, its 
 84.4   report shall provide adequate justification for that conclusion. 
 84.5      (d) Utilities that use or prefer alternative criteria for 
 84.6   measuring individual circuit performance to those described in 
 84.7   paragraphs (b) and (c) and that are required by this section to 
 84.8   submit an annual report of reliability data, shall submit their 
 84.9   alternative listing of circuits along with the criteria used to 
 84.10  rank circuit performance. 
 84.11     (e) Information must be included with respect to any report 
 84.12  on the accomplishment of the improvements proposed in prior 
 84.13  reports for which completion has not been previously reported. 
 84.14     (f) The report must describe any new reliability or power 
 84.15  quality programs and changes that are made to existing programs. 
 84.16     (g) It must include a status report of any long-range 
 84.17  electric distribution plans. 
 84.18     (h) In addition to the information included in paragraph 
 84.19  (b), each utility that has the technical capability and 
 84.20  administrative resources shall report the following additional 
 84.21  service quality information: 
 84.22     (1) route miles of electric distribution line reconstructed 
 84.23  during the year, with separate totals for single- and 
 84.24  three-phase circuits provided; 
 84.25     (2) total route miles of electric distribution line in 
 84.26  service at year's end, segregated by voltage level; 
 84.27     (3) monthly average speed of answer for telephone calls 
 84.28  received regarding emergencies; 
 84.29     (4) the average number of calendar days a utility takes to 
 84.30  install and energize service to a customer site once it is ready 
 84.31  to receive service, with a separate average calculated for each 
 84.32  month, including all extensions energized during the calendar 
 84.33  month; 
 84.34     (5) the total number of written and telephone customer 
 84.35  complaints received in the areas of safety, outages, power 
 84.36  quality, customer property damage, and other areas, by month 
 85.1   filed; 
 85.2      (6) total annual tree-trimming budget and actual expenses; 
 85.3   and 
 85.4      (7) total annual projected and actual miles of tree-trimmed 
 85.5   distribution line. 
 85.6      Sec. 4.  [216B.84] [INITIAL HISTORICAL RELIABILITY 
 85.7   PERFORMANCE REPORT.] 
 85.8      (a) Each electric utility with 10,000 retail customers or 
 85.9   more that has historically used measures of system, operating 
 85.10  area, and circuit reliability performance shall initially submit 
 85.11  annual system average interruption frequency index, system 
 85.12  average interruption duration index, and customer average 
 85.13  interruption duration index data for the previous three years.  
 85.14  Those utilities that have this data for some time period less 
 85.15  than three years shall submit data for those years it is 
 85.16  available. 
 85.17     (b) Those utilities whose historical reliability 
 85.18  performance data is similar or related to those measures listed 
 85.19  in paragraph (a), but differs due to how the parameters are 
 85.20  defined or calculated, shall submit the data it has and explain 
 85.21  any material differences from the prescribed indices.  After the 
 85.22  effective date of this section, utilities shall modify their 
 85.23  reliability performance measures to conform to those specified 
 85.24  in sections 216B.80 to 216B.86 for purposes of consistent 
 85.25  reporting of comparable data in the future. 
 85.26     Sec. 5.  [216B.85] [INTERRUPTIONS OF SERVICE; RECORDS; 
 85.27  NOTICE.] 
 85.28     Subdivision 1.  [RECORDS.] (a) Each utility shall keep 
 85.29  records of all interruptions to service affecting the entire 
 85.30  distribution system of any single community or an important 
 85.31  division of a community, and include in the records each 
 85.32  interruption's location, date and time, and duration; the 
 85.33  approximate number of customers affected; the circuit or 
 85.34  circuits involved; and, when known, the cause of each 
 85.35  interruption. 
 85.36     (b) When complete distribution systems or portions of 
 86.1   communities have service furnished from unattended stations, 
 86.2   these records must be kept to the extent practicable.  The 
 86.3   record of unattended stations shall show interruptions that 
 86.4   require attention to restore service, with the estimated time of 
 86.5   interruption.  Breaker or fuse operations affecting service 
 86.6   should also be indicated even though duration of interruption 
 86.7   may not be known. 
 86.8      Subd. 2.  [NOTICE OF INTERRUPTIONS OF BULK POWER SUPPLY 
 86.9   FACILITIES.] (a) Each utility owning or operating bulk power 
 86.10  supply facilities shall record any event described in clauses 
 86.11  (1) to (5) involving any generating unit or electric facilities 
 86.12  operating at a nominal voltage of 69 kilovolts or higher, and 
 86.13  shall make such records available to the commission 
 86.14  semi-annually or upon request of the commission: 
 86.15     (1) any interruption or loss of service to customers for 15 
 86.16  minutes or more to aggregate firm loads in excess of 200,000 
 86.17  kilowatts; 
 86.18     (2) any interruption or loss of service to customers for 15 
 86.19  minutes or more to aggregate firm loads exceeding the lesser of 
 86.20  100,000 kilowatts or one-half of the current annual system peak 
 86.21  load and not required recorded under clause (1); 
 86.22     (3) any decision to issue a public request for reduction in 
 86.23  use of electricity; 
 86.24     (4) an action to reduce firm customer loads by reduction of 
 86.25  voltage for reasons of maintaining adequacy of bulk electric 
 86.26  power supply; and 
 86.27     (5) any action to reduce firm customer loads by manual 
 86.28  switching, operation of automatic load-shedding devices, or any 
 86.29  other means for reasons of maintaining adequacy of bulk electric 
 86.30  power supply.  
 86.31     Subd. 3.  [NOTICE OF OTHER INTERRUPTIONS OF POWER.] Each 
 86.32  utility shall record service interruptions of 60 minutes or more 
 86.33  to an entire distribution substation bus or entire feeder 
 86.34  serving either 500 or more customers or entire cities or 
 86.35  villages having 200 or more customers.  
 86.36     Subd. 4.  [INFORMATION REQUIRED.] The written records 
 87.1   required in subdivisions 2 and 3 must include the date, time, 
 87.2   duration, general location, approximate number of customers 
 87.3   affected, identification of circuit or circuits involved, and, 
 87.4   when known, the cause of the interruption.  When extensive 
 87.5   interruptions occur, as from a storm, a narrative record 
 87.6   including the extent of the interruptions and system damage, 
 87.7   estimated number of customers affected, and a list of entire 
 87.8   communities interrupted may be recorded in lieu of records of 
 87.9   individual interruptions.  When customer service interruptions 
 87.10  are necessary, the utility shall make reasonable efforts to 
 87.11  notify affected customers in advance.  
 87.12     Sec. 6.  [216B.86] [CUSTOMERS' COMPLAINTS.] 
 87.13     Each utility shall keep a record of complaints received by 
 87.14  it from its customers in regard to safety or service, and the 
 87.15  operation of its system, with appropriate response times 
 87.16  designated for critical safety and monetary loss situations and 
 87.17  shall investigate if appropriate.  The record must show the name 
 87.18  and address of the complainant, the date and nature of the 
 87.19  complaint, the priority assigned to the assistance, and its 
 87.20  disposition and the time and date of its disposition. 
 87.21     Sec. 7.  [216B.87] [STANDARDS FOR DISTRIBUTION UTILITIES.] 
 87.22     (a) The commission and each cooperative electric 
 87.23  association and municipal utility shall adopt standards for 
 87.24  safety, reliability, and service quality for distribution 
 87.25  utilities.  Standards for cooperative electric associations and 
 87.26  municipal utilities should be as consistent as possible with the 
 87.27  commission standards. 
 87.28     (b) Reliability standards must be based on the system 
 87.29  average interruption frequency index, system average 
 87.30  interruption duration index, and customer average interruption 
 87.31  duration index measurement indices.  Service quality standards 
 87.32  must specify, if technically and administratively feasible: 
 87.33     (1) average call center response time; 
 87.34     (2) customer disconnection rate; 
 87.35     (3) meter-reading frequency; 
 87.36     (4) complaint resolution response time; and 
 88.1      (5) service extension request response time. 
 88.2      (c) Minimum performance standards developed under this 
 88.3   section must treat similarly situated distribution systems 
 88.4   similarly and recognize differing characteristics of system 
 88.5   design and hardware. 
 88.6      (d) Electric distribution utilities shall comply with all 
 88.7   applicable governmental and industry standards required for the 
 88.8   safety, design, construction and operation of electric 
 88.9   distribution facilities, including section 326.243.