SF 722

2nd Unofficial Engrossment - 82nd Legislature (2001 - 2002) Posted on 12/15/2009 12:00am

  1.1                          A bill for an act 
  1.2             relating to energy; enacting the Minnesota Energy 
  1.3             Security and Reliability Act; requiring an energy 
  1.4             security blueprint and a state transmission plan; 
  1.5             establishing position of reliability administrator; 
  1.6             providing for essential energy infrastructure; 
  1.7             modifying provisions for siting, routing, and 
  1.8             determining the need for large electric power 
  1.9             facilities; regulating conservation expenditures by 
  1.10            energy utilities and eliminating state pre-approval of 
  1.11            conservation plans by public utilities; encouraging 
  1.12            regulatory flexibility in supplying and obtaining 
  1.13            energy; regulating interconnection of distributed 
  1.14            utility resources; providing for safety and service 
  1.15            standards from distribution utilities; clarifying the 
  1.16            state cold weather disconnection requirements; 
  1.17            authorizing municipal utilities, municipal power 
  1.18            agencies, cooperative utilities, and investor-owned 
  1.19            utilities to form joint ventures to provide utility 
  1.20            services; eliminating the requirement for individual 
  1.21            utility resource plans; requiring reports; making 
  1.22            technical, conforming, and clarifying changes; 
  1.23            amending Minnesota Statutes 2000, sections 116.07, 
  1.24            subdivision 4a; 116C.52, subdivision 10; 116C.53, 
  1.25            subdivisions 2, 3; 116C.57, subdivisions 1, 2, 4, by 
  1.26            adding subdivisions; 116C.58; 116C.59, subdivisions 1, 
  1.27            4; 116C.60; 116C.61, subdivision 1; 116C.62; 116C.64; 
  1.28            116C.645; 116C.65; 116C.66; 116C.69; 216A.03, 
  1.29            subdivision 3a; 216B.095; 216B.097, subdivision 1; 
  1.30            216B.16, subdivisions 7, 15; 216B.2421, subdivision 2, 
  1.31            by adding a subdivision; 216B.2422, subdivision 2; 
  1.32            216B.243, subdivisions 2, 3, 4, by adding a 
  1.33            subdivision; 216C.051, subdivision 9; 216C.41, 
  1.34            subdivision 5, by adding a subdivision; proposing 
  1.35            coding for new law in Minnesota Statutes, chapters 
  1.36            116C; 216B; 216C; 452; repealing Minnesota Statutes 
  1.37            2000, sections 116C.55; 116C.57, subdivisions 3, 5, 
  1.38            5a; 116C.67; 216B.241; 216C.18. 
  1.39  BE IT ENACTED BY THE LEGISLATURE OF THE STATE OF MINNESOTA: 
  1.40                             ARTICLE 1
  1.41                          ENERGY PLANNING
  1.42     Section 1.  [TITLE.] 
  2.1      This act shall be known as the Minnesota Energy Security 
  2.2   and Reliability Act. 
  2.3      Sec. 2.  [216B.012] [STATE TRANSMISSION PLAN.] 
  2.4      Subdivision 1.  [PLAN.] The commission shall maintain a 
  2.5   state transmission plan, consisting of a list of certified high 
  2.6   voltage transmission line projects. 
  2.7      Subd. 2.  [PLAN DEVELOPMENT.] (a) By November 1 of each 
  2.8   odd-numbered year, each public utility, municipal utility, and 
  2.9   cooperative electric association, or the generation and 
  2.10  transmission organization that serves each utility or 
  2.11  association, that owns or operates electric transmission lines 
  2.12  in Minnesota shall jointly or individually submit a transmission 
  2.13  projects report to the commission.  The report must: 
  2.14     (1) list specific present and reasonably foreseeable future 
  2.15  inadequacies in the transmission system in Minnesota; 
  2.16     (2) identify alternative means of addressing each 
  2.17  inadequacy listed; 
  2.18     (3) identify general economic, environmental, and social 
  2.19  issues associated with each alternative; and 
  2.20     (4) provide a summary of public input the utilities and 
  2.21  associations have gathered related to the list of inadequacies 
  2.22  and the role of local government officials and other interested 
  2.23  persons in assisting to develop the list and analyze 
  2.24  alternatives. 
  2.25     (b) To meet the requirements of this subdivision, entities 
  2.26  may rely on available information and analysis developed by a 
  2.27  regional transmission organization or any subgroup of a regional 
  2.28  transmission organization and may develop and include additional 
  2.29  information as necessary.  A regional energy infrastructure 
  2.30  planning report issued under section 216B.019 and submitted 
  2.31  under this subdivision satisfies the requirements of this 
  2.32  subdivision for the member utilities. 
  2.33     Subd. 3.  [COMMISSION APPROVAL.] By June 1 of each 
  2.34  even-numbered year, the commission shall adopt a state 
  2.35  transmission plan and shall certify, certify as modified, or 
  2.36  deny certification of the projects proposed under subdivision 
  3.1   2.  The commission may only certify a project that is a high 
  3.2   voltage transmission line as defined in section 216B.2421, 
  3.3   subdivision 2, that the commission finds is: 
  3.4      (1) necessary to maintain or enhance the reliability of 
  3.5   electric service to Minnesota consumers; 
  3.6      (2) needed, applying the criteria in section 216B.241, 
  3.7   subdivision 3; 
  3.8      (3) a public purpose project, applying the considerations 
  3.9   in section 216B.241, subdivision 2a; and 
  3.10     (4) in the public interest, taking into account electric 
  3.11  energy system needs and economic, environmental, and social 
  3.12  interests affected by the project. 
  3.13     Projects certified as part of the state transmission plan 
  3.14  need no further review by the commission under section 
  3.15  216B.243.  The reliability administrator shall provide technical 
  3.16  assistance to the commissioner and the commission in reviewing 
  3.17  the proposed projects. 
  3.18     Subd. 4.  [CONTINUING OBLIGATION.] Each public utility, 
  3.19  municipal utility, and cooperative electric association that 
  3.20  operates and provides electric service in this state has an 
  3.21  existing and continuing obligation to provide reliable, 
  3.22  affordable, safe, and efficient services to their customers in 
  3.23  the state; to plan to meet the resource and infrastructure needs 
  3.24  of those customers; and to ensure that those resources and 
  3.25  infrastructure are sited and constructed, or otherwise acquired. 
  3.26     Sec. 3.  [216B.013] [EXISTING GENERATION FACILITIES.] 
  3.27     In order to continue the low-maintenance and low-cost 
  3.28  service that the existing base-load generation facilities in 
  3.29  Minnesota have provided to Minnesota consumers, and to provide 
  3.30  power to meet the growing demand for electricity by Minnesota 
  3.31  consumers and businesses, it is the policy of the state that 
  3.32  these facilities be maintained and upgraded consistent with 
  3.33  energy policy goals established pursuant to this chapter.  The 
  3.34  public utilities commission, department, and other state 
  3.35  agencies with regulatory jurisdiction over the operation of 
  3.36  these facilities shall take all steps necessary to incorporate 
  4.1   this state policy into the regulatory decisions made by each 
  4.2   respective agency. 
  4.3      Sec. 4.  [216B.014] [ENERGY SECURITY AND RELIABILITY.] 
  4.4      (a) It is a fundamental goal of Minnesota's energy and 
  4.5   utility policy that state policymakers maximize the state's 
  4.6   energy security.  
  4.7      (b) "Energy security" means, among other things, ensuring 
  4.8   that the state's energy sources are: 
  4.9      (1) diverse, including (i) traditional sources such as 
  4.10  coal, natural gas, waste-to-energy, and nuclear facilities, (ii) 
  4.11  renewable sources such as wind, biomass, and agricultural waste 
  4.12  generation, and (iii) high-efficiency, low-emissions distributed 
  4.13  generation sources such as fuel cells and microturbines; 
  4.14     (2) to the extent feasible, produced in the state utilizing 
  4.15  Minnesota's resources; 
  4.16     (3) environmentally sustainable; 
  4.17     (4) available to consumers at affordable and stable rates 
  4.18  or prices; and 
  4.19     (5) above all, reliable.  "Reliable" means, among other 
  4.20  things, that adequate resources and infrastructure are in place, 
  4.21  and are planned for, to provide efficient, dependable, and 
  4.22  secure energy services to Minnesota consumers.  
  4.23     Sec. 5.  [216B.015] [ENERGY SECURITY BLUEPRINT.] 
  4.24     (a) The commissioner shall develop a draft energy security 
  4.25  blueprint by December 15, 2001, and every four years thereafter. 
  4.26  The blueprint must: 
  4.27     (1) identify important trends and issues in energy supply, 
  4.28  consumption, conservation, and costs; 
  4.29     (2) set energy goals; and 
  4.30     (3) develop strategies to meet the goals. 
  4.31     (b) For the purposes of sections 216B.012 to 216B.019, the 
  4.32  terms:  
  4.33     (1) "electric utility" means an entity that is a public 
  4.34  utility; a cooperative electric association providing 
  4.35  generation, transmission, or distribution services; a municipal 
  4.36  utility; or a municipal power agency; and 
  5.1      (2) "energy utility" means an electric utility, or an 
  5.2   entity providing natural gas to retail consumers. 
  5.3      Sec. 6.  [216B.016] [ENERGY BLUEPRINT CONTENTS.] 
  5.4      The energy blueprint must include: 
  5.5      (1) the amount and type of projected statewide energy 
  5.6   consumption over the next ten years; 
  5.7      (2) a determination of whether and the extent to which 
  5.8   existing and anticipated energy production and transportation 
  5.9   facilities will or will not be able to supply needed energy; 
  5.10     (3) a determination of the potential for conservation to 
  5.11  meet some or all of the projected need for energy; 
  5.12     (4) an assessment of the environmental impact of projected 
  5.13  energy consumption over the next ten years, prepared by the 
  5.14  commissioner of the pollution control agency in consultation 
  5.15  with other state agencies and other interested persons, with 
  5.16  strategies to mitigate those impacts; and 
  5.17     (5) benchmarks to measure and monitor supply adequacy and 
  5.18  infrastructure capacity, and to assess the overall reliability 
  5.19  of the state's electric system. 
  5.20     Sec. 7.  [216B.017] [ENERGY GOALS.] 
  5.21     (a) The blueprint must recommend statewide goals and 
  5.22  recommend strategies to accomplish the following goals for: 
  5.23     (1) energy conservation and recovery; 
  5.24     (2) limiting adverse environmental emissions from the 
  5.25  generation of electric energy consumed in the state; 
  5.26     (3) production of electric energy consumed in the state 
  5.27  from renewable energy sources; 
  5.28     (4) deployment of distributed electric generation 
  5.29  technologies; 
  5.30     (5) ensuring that energy service is affordable and 
  5.31  available to all consumers in the state; 
  5.32     (6) minimizing the imposition of social costs on energy 
  5.33  consumers through energy rates or prices; and 
  5.34     (7) increasing the efficiency of the regulatory 
  5.35  infrastructure and reducing regulatory and administrative costs. 
  5.36     (b) The goals adopted in the blueprint may be onetime goals 
  6.1   or a series of goals to meet overall objectives.  The 
  6.2   commissioner shall present these goals, and any associated 
  6.3   strategies that require changes to state law, to the legislature 
  6.4   for modification and approval.  
  6.5      Sec. 8.  [216B.018] [BLUEPRINT DEVELOPMENT.] 
  6.6      Subdivision 1.  [PUBLIC PARTICIPATION.] The commissioner 
  6.7   shall: 
  6.8      (1) invite public and stakeholder comment and participation 
  6.9   during blueprint development; and 
  6.10     (2) hold at least one public meeting on the proposed 
  6.11  blueprint in each energy infrastructure planning region of the 
  6.12  state after at least 30 days' public notice in the region. 
  6.13     Subd. 2.  [NOTICE AND COMMENT; BLUEPRINT ISSUANCE.] The 
  6.14  commissioner shall provide notice of all public meetings to 
  6.15  discuss the proposed blueprint and allow opportunity for written 
  6.16  comment prior to issuing the final blueprint.  After review by 
  6.17  the administrator, the commissioner shall publish the final 
  6.18  energy blueprint in the State Register within four months of 
  6.19  issuing the draft blueprint. 
  6.20     Sec. 9.  [216B.019] [REGIONAL ENERGY INFRASTRUCTURE 
  6.21  PLANNING.] 
  6.22     Subdivision 1.  [ESTABLISHING PLANNING REGIONS.] The 
  6.23  commission, after notice and opportunity for written comment, 
  6.24  shall establish geographic regional energy infrastructure 
  6.25  planning regions in the state by August 1, 2001.  Planning 
  6.26  regions may coincide with existing subregional planning areas 
  6.27  used by the regional electric reliability or regional 
  6.28  transmission organization serving Minnesota.  The commission 
  6.29  shall also request comments on and approve, or approve as 
  6.30  modified, each group's organizational, administrative, planning, 
  6.31  and voting structures. 
  6.32     Subd. 2.  [PLANNING GROUP.] Each energy utility that 
  6.33  operates in an identified region shall participate in the 
  6.34  regional energy infrastructure planning group.  Each regional 
  6.35  group must include as voting members an equal number of 
  6.36  representatives of energy utilities, and representatives from 
  7.1   counties in the identified region, appointed by the county board.
  7.2      Subd. 3.  [PUBLIC MEETINGS.] Each regional energy 
  7.3   infrastructure planning group shall hold public meetings within 
  7.4   the region on a regular basis, not less than twice a year, and 
  7.5   provide public notice at least 14 calendar days in advance of a 
  7.6   meeting. 
  7.7      Subd. 4.  [REPORT.] By November 1, 2001, and every two 
  7.8   years thereafter, each regional energy infrastructure planning 
  7.9   group shall submit a report to the commissioner that: 
  7.10     (1) identifies inadequacies in electric generation and 
  7.11  transmission within the region including any deficiencies as 
  7.12  defined in subdivision 5; 
  7.13     (2) lists alternative ways to address identified 
  7.14  inadequacies, taking into account the provisions of the state 
  7.15  energy security blueprint; 
  7.16     (3) identifies potential general and, to the extent known, 
  7.17  specific economic, environmental, and social issues associated 
  7.18  with each alternative; and 
  7.19     (4) recommends alternatives to address identified 
  7.20  inadequacies and deficiencies that ensure the reliability and 
  7.21  security of the energy system in the region, while minimizing 
  7.22  environmental and social impacts.  In making recommendations, 
  7.23  the planning group shall identify critical needs.  For the 
  7.24  purposes of this clause, "critical needs" are those projects 
  7.25  that are necessary to maintain reliable electric service to 
  7.26  Minnesota consumers that meet or exceed the most stringent 
  7.27  applicable state or regional reliability standards.  A regional 
  7.28  planning group may satisfy the requirement to issue an initial 
  7.29  report under this section by submitting the portion of the 
  7.30  Mid-Continent Area Power Pool transmission plan that affects the 
  7.31  region, with any analysis, comment, or narrative that the group 
  7.32  deems important. 
  7.33     Subd. 5.  [DEFICIENCY.] (a) "Deficiency" means a condition, 
  7.34  or set of conditions, that, based on the utility's most recent 
  7.35  forecast or consistent with the transmission expansion plan of a 
  7.36  federally approved regional transmission organization or 
  8.1   regional reliability entity, may materially limit the adequacy 
  8.2   of electric supply, efficiency of electric service, or 
  8.3   reliability of electric service to an electric utility's 
  8.4   customers in the state that may require construction of a 
  8.5   generation or transmission project. 
  8.6      (b) Within 90 days of identifying a deficiency in its 
  8.7   system, an electric utility shall give notice of the deficiency 
  8.8   to at least: 
  8.9      (1) the members of affected regional energy infrastructure 
  8.10  planning groups; 
  8.11     (2) officials of potentially affected local governments; 
  8.12  and 
  8.13     (3) the commissioner and the independent reliability 
  8.14  administrator. 
  8.15     (c) Notice of deficiency must be made before submitting (1) 
  8.16  an application for a certificate of need under section 216B.243 
  8.17  or (2) a request for environmental review of an energy project 
  8.18  to any governmental entity.  
  8.19     Sec. 10.  Minnesota Statutes 2000, section 216C.051, 
  8.20  subdivision 9, is amended to read: 
  8.21     Subd. 9.  [EXPIRATION.] This section is repealed March 15, 
  8.22  2001 June 30, 2003. 
  8.23     Sec. 11.  [216C.052] [RELIABILITY ADMINISTRATOR.] 
  8.24     Subdivision 1.  [POSITION ESTABLISHED IN 
  8.25  DEPARTMENT.] Recognizing the critical importance of adequate, 
  8.26  reliable, and environmentally sound energy services to the 
  8.27  state's economy and the well being of its citizens, and that 
  8.28  independent and expert technical analysis is necessary to ensure 
  8.29  the reliability of the energy system, the position of 
  8.30  reliability administrator is established within the department 
  8.31  of commerce. 
  8.32     Subd. 2.  [RESPONSIBILITIES.] (a) The administrator shall 
  8.33  provide technical advice and assistance to the department, the 
  8.34  commission, and regional energy infrastructure planning groups. 
  8.35  In addition, the administrator shall provide technical and 
  8.36  administrative assistance to the legislative electric energy 
  9.1   task force.  In conducting its work, the administrator shall: 
  9.2      (1) model and monitor the use and operation of the energy 
  9.3   infrastructure in the state, including generation facilities, 
  9.4   transmission lines, natural gas pipelines, and other energy 
  9.5   infrastructure; 
  9.6      (2) develop and present to the commission and parties 
  9.7   technical analyses of proposed infrastructure projects, and 
  9.8   provide technical advice to the commission; 
  9.9      (3) assist the regional energy infrastructure planning 
  9.10  groups in analyzing assertions of need for additional 
  9.11  infrastructure; 
  9.12     (4) develop and present the reliability status report 
  9.13  required under subdivision 4 and the state reliability plan 
  9.14  under section 216B.012; and 
  9.15     (5) present independent, factual, expert, and technical 
  9.16  information on infrastructure proposals at public meetings 
  9.17  hosted by the task force, the environmental quality board, or 
  9.18  the commission. 
  9.19     (b) Upon request and subject to resource constraints, the 
  9.20  administrator shall provide technical assistance regarding 
  9.21  matters unrelated to applications for infrastructure 
  9.22  improvements to the task force, the department, or the 
  9.23  commission. 
  9.24     Subd. 3.  [ADMINISTRATIVE ISSUES.] (a) The commissioner may 
  9.25  select the administrator whose term shall be concurrent with 
  9.26  that of the governor.  The administrator may be removed only for 
  9.27  cause.  The commissioner shall oversee and direct the work of 
  9.28  the administrator, annually review the expenses of the 
  9.29  administrator, and biennially approve the budget of the 
  9.30  administrator.  The administrator may utilize existing 
  9.31  commission or department staff at the discretion of the chair or 
  9.32  the commissioner, may hire staff, and may contract for technical 
  9.33  expertise in performing duties when existing state resources are 
  9.34  required for other state responsibilities or when special 
  9.35  expertise is required.  The salary of the administrator is 
  9.36  governed by section 15A.0815, subdivision 2. 
 10.1      (b) The administrator shall certify its administrative 
 10.2   costs to the commission on a monthly basis, and shall specify 
 10.3   those costs that are general in nature and those that were 
 10.4   incurred on a specific application or with regard to a specific 
 10.5   utility.  
 10.6      (c) The department of commerce shall pay the certified 
 10.7   general administrative costs of the administrator, and shall 
 10.8   assess energy utilities for reimbursement for those 
 10.9   administrative costs.  The department shall apportion those 
 10.10  costs among all energy utilities in proportion to their 
 10.11  respective gross operating revenues from retail sales of gas or 
 10.12  electric service within the state during the last calendar year, 
 10.13  and shall then render a bill to each utility on a regular 
 10.14  basis.  For the purposes of this subdivision, "energy utility" 
 10.15  has the meaning given to it in section 216B.015, paragraph (b).  
 10.16  The assessment authority of the legislative electric energy task 
 10.17  force pursuant to section 216C.051, subdivision 6, shall be 
 10.18  reduced by the amount of the administrator's certified general 
 10.19  administrative costs.  If sufficient assessment authority is not 
 10.20  available under that subdivision or section 216C.051 expires, 
 10.21  the administrator must not incur additional costs and the 
 10.22  position of administrator must be vacated.  In no event shall 
 10.23  the general fund of the state treasury be responsible for any 
 10.24  costs of the administrator. 
 10.25     (d) Costs relating to a specific proceeding, analysis, or 
 10.26  project are not general administrative costs.  The department 
 10.27  shall pay those certified costs, and shall render a bill for 
 10.28  reimbursement to the specific energy utility or utilities 
 10.29  participating in the proceeding, analysis, or project directly 
 10.30  either at the conclusion of a particular proceeding, analysis, 
 10.31  or project, or from time to time during the course of the 
 10.32  proceeding, analysis, or project.  
 10.33     (e) For the purposes of administrative efficiency, the 
 10.34  department shall assess energy utilities and issue bills in 
 10.35  accordance with the billing and assessment procedures provided 
 10.36  in section 216B.62, to the extent that such procedures do not 
 11.1   conflict with the provisions of this subdivision.  A bill 
 11.2   rendered by the department under paragraph (c) or (d) 
 11.3   constitutes notice of the assessment and a demand for payment.  
 11.4   The amount of the bills so rendered by the department must be 
 11.5   paid by the energy utility into an account in the special 
 11.6   revenue fund in the state treasury within 30 days from the date 
 11.7   of billing and is appropriated to the commissioner for the 
 11.8   purposes provided in this section.  Appeals may be handled by 
 11.9   the commission as provided in section 216B.62.  The commission 
 11.10  shall approve or approve as modified a rate schedule providing 
 11.11  for the automatic adjustment of charges to recover amounts paid 
 11.12  by utilities under this section.  The administrator shall 
 11.13  provide a detailed accounting of finances to the commissioner 
 11.14  and to the chairs of the house of representatives and senate 
 11.15  finance committees with jurisdiction over the department's 
 11.16  budget.  All amounts assessed under this section are in addition 
 11.17  to amounts appropriated to the commission and the department by 
 11.18  other law.  
 11.19     Subd. 4.  [RELIABILITY STATUS REPORT.] The commission shall 
 11.20  require all electric utilities to report to the administrator on 
 11.21  operating and planning reserves, available transmission 
 11.22  capacity, outages of major generation units and feeders of 
 11.23  distribution and transmissions facilities, the adequacy of stock 
 11.24  and equipment, and any other information necessary to assess the 
 11.25  current and future reliability of energy service in this state.  
 11.26  By January 1 of each odd-numbered year beginning in 2003, the 
 11.27  administrator shall assess and report the status of the 
 11.28  reliability of electric service in the state to the 
 11.29  commissioner, with copies to the commission and the legislative 
 11.30  electric energy task force. 
 11.31     Sec. 12.  [EFFECTIVE DATE.] 
 11.32     Article 1 is effective the day following final enactment. 
 11.33                             ARTICLE 2
 11.34                  ESSENTIAL ENERGY INFRASTRUCTURE
 11.35     Section 1.  Minnesota Statutes 2000, section 116.07, 
 11.36  subdivision 4a, is amended to read: 
 12.1      Subd. 4a.  [PERMITS.] (a) The pollution control agency may 
 12.3   issue, continue in effect, or deny permits, under such 
 12.4   conditions as it may prescribe for the prevention of pollution, 
 12.5   for (1) the emission of air contaminants except for emissions 
 12.6   from electric generation stations, or for (2) the installation 
 12.7   or operation of any emission facility, air contaminant treatment 
 12.8   facility, treatment facility, potential air contaminant storage 
 12.9   facility, or storage facility, or any part thereof, or for (3) 
 12.10  the sources or emissions of noise pollution. 
 12.11     The pollution control agency may also issue, continue in 
 12.12  effect or deny permits, under such conditions as it may 
 12.13  prescribe for the prevention of pollution, for, (4) the storage, 
 12.14  collection, transportation, processing, or disposal of waste, or 
 12.15  for (5) the installation or operation of any system or facility, 
 12.16  or any part thereof, related to the storage, collection, 
 12.17  transportation, processing, or disposal of waste.  The 
 12.18  commissioner, rather than the agency, may issue, continue in 
 12.19  effect, or deny permits, under conditions the commissioner may 
 12.20  prescribe for the prevention of pollution, for the emissions of 
 12.21  air contaminants from electric generation stations.  
 12.22  The pollution control agency may revoke or modify any permit 
 12.23  issued under this subdivision and section 116.081 whenever it is 
 12.24  necessary, in the opinion of the agency, to prevent or abate 
 12.25  pollution. 
 12.26     (b) The pollution control agency has the authority for 
 12.27  approval over the siting, expansion, or operation of a solid 
 12.28  waste facility with regard to environmental issues.  However, 
 12.29  the agency's issuance of a permit does not release the permittee 
 12.30  from any liability, penalty, or duty imposed by any applicable 
 12.31  county ordinances.  Nothing in this chapter precludes, or shall 
 12.32  be construed to preclude, a county from enforcing land use 
 12.33  controls, regulations, and ordinances existing at the time of 
 12.34  the permit application and adopted pursuant to sections 366.10 
 12.35  to 366.181, 394.21 to 394.37, or 462.351 to 462.365, with regard 
 12.36  to the siting, expansion, or operation of a solid waste facility.
 12.37     Sec. 2.  Minnesota Statutes 2000, section 116C.52, 
 13.1   subdivision 10, is amended to read: 
 13.2      Subd. 10.  [UTILITY.] "Utility" shall mean any entity 
 13.3   engaged or intending to engage in this state in the generation, 
 13.4   transmission or distribution of electric energy including, but 
 13.5   not limited to, a private investor owned utility, cooperatively 
 13.6   owned utility, and a public or municipally owned utility. 
 13.7      Sec. 3.  Minnesota Statutes 2000, section 116C.53, 
 13.8   subdivision 2, is amended to read: 
 13.9      Subd. 2.  [JURISDICTION.] The board is hereby given the 
 13.10  authority to provide for site and route selection for large 
 13.11  electric power facilities.  The board shall issue permits for 
 13.12  large electric power facilities in a timely fashion.  When the 
 13.13  public utilities commission has determined the need for the 
 13.14  project under section 216B.012 or 216B.243, questions of need, 
 13.15  including size, type, and timing; alternative system 
 13.16  configurations; and voltage, are not within the board's siting 
 13.17  and routing authority and must not be included in the scope of 
 13.18  environmental review conducted under sections 116C.51 to 116C.69.
 13.19     Sec. 4.  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 designating a 
 13.25  route.  The board, in discharge of its duties pursuant to 
 13.26  sections 116C.51 to 116C.69 may make joint investigations, hold 
 13.27  joint hearings within or without the state, and issue joint or 
 13.28  concurrent orders in conjunction or concurrence with any 
 13.29  official or agency of any state or of the United States.  The 
 13.30  board may negotiate and enter into any agreements or compacts 
 13.31  with agencies of other states, pursuant to any consent of 
 13.32  Congress, for cooperative efforts in certifying the 
 13.33  construction, operation, and maintenance of large electric power 
 13.34  facilities in accord with the purposes of sections 116C.51 to 
 13.35  116C.69 and for the enforcement of the respective state laws 
 13.36  regarding such 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. 5.  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.  If 
 15.9   the proposed project is under the jurisdiction of the board, the 
 15.10  board must incorporate into one proceeding the route selection 
 15.11  for a high voltage transmission line that is directly associated 
 15.12  with and necessary to interconnect the large electric generation 
 15.13  plant to the transmission system and whose need is certified as 
 15.14  part of the generation plant project by the public utilities 
 15.15  commission.  
 15.16     Sec. 6.  Minnesota Statutes 2000, section 116C.57, 
 15.17  subdivision 2, is amended to read: 
 15.18     Subd. 2.  [DESIGNATION OF ROUTES; PROCEDURE ROUTE PERMIT.] 
 15.19  A utility shall apply to the board in a form and manner 
 15.20  prescribed by the board for a permit for the construction of a 
 15.21  high voltage transmission line.  The application shall contain 
 15.22  at least two proposed routes.  Pursuant to sections 116C.57 to 
 15.23  116C.60, the board shall study, and evaluate the type, design, 
 15.24  routing, right-of-way preparation and facility construction of 
 15.25  any route proposed in a utility's application and any other 
 15.26  route the board deems necessary which was proposed in a manner 
 15.27  consistent with rules adopted by the board concerning the form, 
 15.28  content, and timeliness of proposals for alternate routes 
 15.29  provided, however, that the board shall identify the alternative 
 15.30  routes prior to the commencement of public hearings thereon 
 15.31  pursuant to section 116C.58.  Within one year after the board's 
 15.32  acceptance of a utility's application, the board shall decide in 
 15.33  accordance with the criteria and standards specified in section 
 15.34  116C.55, subdivision 2, and the considerations specified in 
 15.35  section 116C.57, subdivision 4, which proposed route is to be 
 15.36  designated.  The board may extend for just cause the time 
 16.1   limitation for its decision for a period not to exceed 90 days.  
 16.2   When the board designates a route, it shall issue a permit for 
 16.3   the construction of a high voltage transmission line specifying 
 16.4   the type, design, routing, right-of-way preparation and facility 
 16.5   construction it deems necessary and with any other appropriate 
 16.6   conditions.  The board may order the construction of high 
 16.7   voltage transmission line facilities which are capable of 
 16.8   expansion in transmission capacity through multiple circuiting 
 16.9   or design modifications.  The board shall publish a notice of 
 16.10  its decision in the state register within 30 days of issuance of 
 16.11  the permit.  No person may construct a high voltage transmission 
 16.12  line shall be constructed except on without a route designated 
 16.13  by permit from the board, unless it was exempted pursuant to 
 16.14  subdivision 5.  A high voltage transmission line may be 
 16.15  constructed only along a route approved by the board.  
 16.16     Sec. 7.  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; and 
 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.  An application is not incomplete if information 
 16.36  not in the application can be obtained from the applicant during 
 17.1   the first phase of the process and that information is not 
 17.2   essential for notice and initial public meetings. 
 17.3      Sec. 8.  Minnesota Statutes 2000, section 116C.57, is 
 17.4   amended by adding a subdivision to read: 
 17.5      Subd. 2b.  [NOTICE OF APPLICATION.] Within 15 days after 
 17.6   submitting an application to the board, the applicant shall 
 17.7   publish notice of the application in a legal newspaper of 
 17.8   general circulation in each county in which the site or route is 
 17.9   proposed and send a copy of the application by certified mail to 
 17.10  any regional development commission, county, incorporated 
 17.11  municipality, and town in which the site or route is proposed.  
 17.12  Within the same 15 days, the applicant shall also send a notice 
 17.13  of the submission of the application and description of the 
 17.14  proposed project to each owner whose property is adjacent to any 
 17.15  of the proposed sites for the power plant or along any of the 
 17.16  proposed routes for the transmission line.  The notice must 
 17.17  identify a location where a copy of the application can be 
 17.18  reviewed.  For the purpose of giving mailed notice under this 
 17.19  subdivision, owners are those shown on the records of the county 
 17.20  auditor or, in any county where tax statements are mailed by the 
 17.21  county treasurer, on the records of the county treasurer, but 
 17.22  other appropriate records may be used for this purpose.  The 
 17.23  failure to give mailed notice to a property owner, or defects in 
 17.24  the notice, does not invalidate the proceedings, provided a bona 
 17.25  fide attempt to comply with this subdivision has been made.  
 17.26  Within the same 15 days, the applicant shall also send the same 
 17.27  notice of the submission of the application and description of 
 17.28  the proposed project to those persons who have requested to be 
 17.29  placed on a list maintained by the board for receiving notice of 
 17.30  proposed large electric generating power plants and high voltage 
 17.31  transmission lines. 
 17.32     Sec. 9.  Minnesota Statutes 2000, section 116C.57, is 
 17.33  amended by adding a subdivision to read: 
 17.34     Subd. 2c.  [ENVIRONMENTAL REVIEW.] The board shall prepare 
 17.35  an environmental impact statement on each proposed large 
 17.36  electric generating plant or high voltage transmission line for 
 18.1   which a complete application has been submitted.  For any 
 18.2   project that has obtained a certificate of need from the public 
 18.3   utilities commission, the board shall not consider whether or 
 18.4   not the project is needed.  No other state environmental review 
 18.5   documents are required.  The board shall study and evaluate any 
 18.6   site or route proposed by an applicant and any other site or 
 18.7   route 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. 10.  Minnesota Statutes 2000, section 116C.57, is 
 18.12  amended by adding a subdivision to read: 
 18.13     Subd. 2d.  [PUBLIC HEARING.] The board shall hold a public 
 18.14  hearing on an application for a site permit for a large electric 
 18.15  power generating plant or a route permit for a high voltage 
 18.16  transmission line.  A hearing held for designating a site or 
 18.17  route must be conducted by an administrative law judge from the 
 18.18  office of administrative hearings under the contested case 
 18.19  procedures of chapter 14.  Notice of the hearing must be given 
 18.20  by the board at least ten days in advance but no earlier than 45 
 18.21  days prior to the commencement of the hearing.  Notice must be 
 18.22  by publication in a legal newspaper of general circulation in 
 18.23  the county in which the public hearing is to be held and by 
 18.24  certified mail to chief executives of the regional development 
 18.25  commissions, counties, organized towns, townships, and the 
 18.26  incorporated municipalities in which a site or route is 
 18.27  proposed.  A person may appear at the hearing and offer 
 18.28  testimony and exhibits without the necessity of intervening as a 
 18.29  formal party to the proceeding.  The administrative law judge 
 18.30  may allow a person to ask questions of other witnesses.  The 
 18.31  administrative law judge shall hold a portion of the hearing in 
 18.32  the area where the power plant or transmission line is proposed 
 18.33  to be located. 
 18.34     Sec. 11.  Minnesota Statutes 2000, section 116C.57, 
 18.35  subdivision 4, is amended to read: 
 18.36     Subd. 4.  [CONSIDERATIONS IN DESIGNATING SITES AND 
 19.1   ROUTES.] (a) To facilitate the study, research, evaluation, and 
 19.2   designation of sites and routes, the board shall be guided by, 
 19.3   but not limited to, the following responsibilities, procedures, 
 19.4   and considerations: 
 19.5      (1) evaluation of research and investigations relating to 
 19.6   the effects on land, water, and air resources of large electric 
 19.7   power generating plants and high voltage transmission line 
 19.8   routes and the effects of water and air discharges and electric 
 19.9   fields resulting from such facilities on public health and 
 19.10  welfare, vegetation, animals, materials, and aesthetic values, 
 19.11  including base line studies, predictive modeling, and monitoring 
 19.12  of the water and air mass at proposed and operating sites and 
 19.13  routes, evaluation of new or improved methods for minimizing 
 19.14  adverse impacts of water and air discharges and other matters 
 19.15  pertaining to the effects of power plants on the water and air 
 19.16  environment; 
 19.17     (2) environmental evaluation of sites and routes proposed 
 19.18  for future development and expansion and their relationship to 
 19.19  the land, water, air, and human resources of the state; 
 19.20     (3) evaluation of the effects of new electric power 
 19.21  generation and transmission technologies and systems related to 
 19.22  power plants designed to minimize adverse environmental effects; 
 19.23     (4) evaluation of the potential for beneficial uses of 
 19.24  waste energy from proposed large electric power generating 
 19.25  plants; 
 19.26     (5) analysis of the direct and indirect economic impact of 
 19.27  proposed sites and routes including, but not limited to, 
 19.28  productive agricultural land lost or impaired; 
 19.29     (6) evaluation of adverse direct and indirect environmental 
 19.30  effects which that cannot be avoided should the proposed site 
 19.31  and route be accepted; 
 19.32     (7) evaluation of alternatives to the applicant's proposed 
 19.33  site or route proposed pursuant to subdivisions 1 and 2; 
 19.34     (8) evaluation of potential routes which that would use or 
 19.35  parallel existing railroad and highway rights-of-way; 
 19.36     (9) evaluation of governmental survey lines and other 
 20.1   natural division lines of agricultural land so as to minimize 
 20.2   interference with agricultural operations; 
 20.3      (10) evaluation of the future needs for additional high 
 20.4   voltage transmission lines in the same general area as any 
 20.5   proposed route, and the advisability of ordering the 
 20.6   construction of structures capable of expansion in transmission 
 20.7   capacity through multiple circuiting or design modifications; 
 20.8      (11) evaluation of irreversible and irretrievable 
 20.9   commitments of resources should the proposed site or route be 
 20.10  approved; and 
 20.11     (12) where when appropriate, consideration of problems 
 20.12  raised by other state and federal agencies and local entities. 
 20.13     (13) (b) If the board's rules are substantially similar to 
 20.14  existing rules and regulations of a federal agency to which the 
 20.15  utility in the state is subject, the federal rules and 
 20.16  regulations shall must be applied by the board. 
 20.17     (14) (c) No site or route shall may be designated which 
 20.18  violates if to do so would violate state agency rules. 
 20.19     Sec. 12.  Minnesota Statutes 2000, section 116C.57, is 
 20.20  amended by adding a subdivision to read: 
 20.21     Subd. 7.  [TIMING.] The board shall make a final decision 
 20.22  on an application within 60 days after receipt of the report of 
 20.23  the administrative law judge.  A final decision on the request 
 20.24  for a site permit or route permit shall be made within one year 
 20.25  after the chair's determination that an application is 
 20.26  complete.  The time for the final decision may be extended for 
 20.27  up to 90 days for good cause and if all parties agree. 
 20.28     Sec. 13.  Minnesota Statutes 2000, section 116C.57, is 
 20.29  amended by adding a subdivision to read: 
 20.30     Subd. 8.  [FINAL DECISION.] (a) A site permit may not be 
 20.31  issued in violation of the site selection standards and criteria 
 20.32  established in this section and in rules adopted by the board.  
 20.33  The board shall indicate the reasons for any refusal and 
 20.34  indicate changes in size or type of facility necessary to allow 
 20.35  site designation.  When the board designates a site, it shall 
 20.36  issue a site permit to the applicant with any appropriate 
 21.1   conditions.  The board shall publish a notice of its decision in 
 21.2   the State Register within 30 days of issuing the site permit. 
 21.3      (b) A route permit may not be issued in violation of the 
 21.4   route selection standards and criteria established in this 
 21.5   section and in rules adopted by the board.  When the route is 
 21.6   designated, the permit issued for the construction of the 
 21.7   facility must specify the type, design, routing, right-of-way 
 21.8   preparation, and facility construction deemed necessary and any 
 21.9   other appropriate conditions.  The board may order the 
 21.10  construction of high voltage transmission line facilities that 
 21.11  are capable of expansion in transmission capacity through 
 21.12  multiple circuiting or design modifications.  The board shall 
 21.13  publish a notice of its decision in the State Register within 30 
 21.14  days of issuing the permit. 
 21.15     Sec. 14.  [116C.575] [ALTERNATIVE REVIEW OF APPLICATIONS.] 
 21.16     Subdivision 1.  [ALTERNATIVE REVIEW.] An applicant who 
 21.17  seeks a site permit or route permit for one of the projects 
 21.18  identified in this section may petition the board to be allowed 
 21.19  to follow the procedures in this section rather than the 
 21.20  procedures in section 116C.57.  The board shall grant the 
 21.21  petition within 30 days unless the board finds good cause for 
 21.22  denial.  
 21.23     Subd. 2.  [APPLICABLE PROJECTS.] The requirements and 
 21.24  procedures in this section may apply to the following projects: 
 21.25     (1) large electric power generating plants with a capacity 
 21.26  of less than 80 megawatts; 
 21.27     (2) large electric power generating plants fueled by 
 21.28  natural gas; 
 21.29     (3) projects to retrofit or repower an existing large 
 21.30  electric power generating plant to one burning primarily natural 
 21.31  gas or other similar clean fuel; 
 21.32     (4) any natural gas peaking facility designed for or 
 21.33  capable of storing on a single site more than 100,000 gallons of 
 21.34  liquefied natural gas or synthetic gas; 
 21.35     (5) high voltage transmission lines in excess of 200 
 21.36  kilovolts less than five miles in length in Minnesota; and 
 22.1      (6) high voltage transmission lines in excess of 200 
 22.2   kilovolts if at least 80 percent of the distance of the line in 
 22.3   Minnesota will be located along existing high voltage 
 22.4   transmission line right-of-way. 
 22.5      Subd. 3.  [APPLICATION.] The applicant for a site 
 22.6   certificate or route permit for any of the projects listed in 
 22.7   subdivision 2 who chooses to follow these procedures shall 
 22.8   submit information the board may require, but the applicant is 
 22.9   not required to propose a second site or route for the project.  
 22.10  The applicant shall identify in the application any other sites 
 22.11  or routes that were rejected by the applicant and the board may 
 22.12  identify additional sites or routes to consider during the 
 22.13  processing of the application.  The chair of the board shall 
 22.14  determine whether an application is complete and advise the 
 22.15  applicant of any deficiencies. 
 22.16     Subd. 4.  [NOTICE OF APPLICATION.] On submitting an 
 22.17  application under this section, the applicant shall provide the 
 22.18  same notice as required by section 116C.57, subdivision 2b. 
 22.19     Subd. 5.  [ENVIRONMENTAL REVIEW.] For the projects 
 22.20  identified in subdivision 2 and following these procedures, the 
 22.21  board shall prepare an environmental assessment worksheet.  The 
 22.22  board shall include as part of the environmental assessment 
 22.23  worksheet alternative sites or routes identified by the board 
 22.24  and shall address mitigating measures for all of the sites or 
 22.25  routes considered.  The environmental assessment worksheet is 
 22.26  the only state environmental review document required to be 
 22.27  prepared on the project. 
 22.28     Subd. 6.  [PUBLIC MEETING.] The board shall hold a public 
 22.29  meeting in the area where the facility is proposed to be 
 22.30  located.  The board shall give notice of the public meeting in 
 22.31  the same manner as notice for a public hearing.  The board shall 
 22.32  provide opportunity at the public meeting for any person to 
 22.33  present comments and to ask questions of the applicant and board 
 22.34  staff.  The board shall also afford interested persons an 
 22.35  opportunity to submit written comments into the record. 
 22.36     Subd. 7.  [TIMING.] The board shall make a final decision 
 23.1   on an application within 60 days after completion of the public 
 23.2   meeting.  A final decision on the request for a site permit or 
 23.3   route permit under this section must be made within six months 
 23.4   after the chair's determination that an application is 
 23.5   complete.  The time for the final decision may be extended for 
 23.6   up to 45 days for good cause and if all parties agree. 
 23.7      Subd. 8.  [CONSIDERATIONS.] The considerations in section 
 23.8   116C.57, subdivision 4, apply to any projects subject to this 
 23.9   section. 
 23.10     Subd. 9.  [FINAL DECISION.] (a) A site permit may not be 
 23.11  issued in violation of the site selection standards and criteria 
 23.12  established in this section and in rules adopted by the board.  
 23.13  The board shall indicate the reasons for any refusal and 
 23.14  indicate changes in size or type of facility necessary to allow 
 23.15  site designation.  When the board designates a site, it shall 
 23.16  issue a site permit to the applicant with any appropriate 
 23.17  conditions.  The board shall publish a notice of its decision in 
 23.18  the State Register within 30 days of issuance of the site permit.
 23.19     (b) A route designation may not be made in violation of the 
 23.20  route selection standards and criteria established in this 
 23.21  section and in rules adopted by the board.  When the board 
 23.22  designates a route, it shall issue a permit for the construction 
 23.23  of a high voltage transmission line specifying the type, design, 
 23.24  routing, right-of-way preparation, and facility construction it 
 23.25  deems necessary and specifying any other appropriate 
 23.26  conditions.  The board may order the construction of high 
 23.27  voltage transmission line facilities that are capable of 
 23.28  expansion in transmission capacity through multiple circuiting 
 23.29  or design modifications.  The board shall publish a notice of 
 23.30  its decision in the State Register within 30 days of issuance of 
 23.31  the permit. 
 23.32     Sec. 15.  [116C.576] [EMERGENCY PERMIT.] 
 23.33     (a) Any utility whose electric power system requires the 
 23.34  immediate construction of a large electric power generating 
 23.35  plant or high voltage transmission line due to a major 
 23.36  unforeseen event may apply to the board for an emergency permit 
 24.1   after providing notice in writing to the public utilities 
 24.2   commission of the major unforeseen event and the need for 
 24.3   immediate construction.  The permit must be issued in a timely 
 24.4   manner, no later than 195 days after the board's acceptance of 
 24.5   the application and upon a finding by the board that (1) a 
 24.6   demonstrable emergency exists, (2) the emergency requires 
 24.7   immediate construction, and (3) adherence to the procedures and 
 24.8   time schedules specified in section 116C.57 would jeopardize the 
 24.9   utility's electric power system or would jeopardize the 
 24.10  utility's ability to meet the electric needs of its customers in 
 24.11  an orderly and timely manner. 
 24.12     (b) A public hearing to determine if an emergency exists 
 24.13  must be held within 90 days of the application.  The board, 
 24.14  after notice and hearing, shall adopt rules specifying the 
 24.15  criteria for emergency certification.  
 24.16     Sec. 16.  Minnesota Statutes 2000, section 116C.58, is 
 24.17  amended to read: 
 24.18     116C.58 [PUBLIC HEARINGS; NOTICE ANNUAL HEARING.] 
 24.19     The board shall hold an annual public hearing at a time and 
 24.20  place prescribed by rule in order to afford interested persons 
 24.21  an opportunity to be heard regarding its inventory of study 
 24.22  areas and any other aspects of the board's activities and duties 
 24.23  or policies specified in sections 116C.51 to 116C.69.  The board 
 24.24  shall hold at least one public hearing in each county where a 
 24.25  site or route is being considered for designation pursuant to 
 24.26  section 116C.57.  Notice and agenda of public hearings and 
 24.27  public meetings of the board held in each county shall be given 
 24.28  by the board at least ten days in advance but no earlier than 45 
 24.29  days prior to such hearings or meetings.  Notice shall be by 
 24.30  publication in a legal newspaper of general circulation in the 
 24.31  county in which the public hearing or public meeting is to be 
 24.32  held and by certified mailed notice to chief executives of the 
 24.33  regional development commissions, counties, organized towns and 
 24.34  the incorporated municipalities in which a site or route is 
 24.35  proposed.  All hearings held for designating a site or route or 
 24.36  for exempting a route shall be conducted by an administrative 
 25.1   law judge from the office of administrative hearings pursuant to 
 25.2   the contested case procedures of chapter 14.  Any person may 
 25.3   appear at the hearings and present testimony and exhibits and 
 25.4   may question witnesses without the necessity of intervening as a 
 25.5   formal party to the proceedings. any matters relating to the 
 25.6   siting of large electric generating power plants and routing of 
 25.7   high voltage transmission lines.  At the meeting, the board 
 25.8   shall advise the public of the permits issued by the board in 
 25.9   the past year.  The board shall provide at least ten days' 
 25.10  notice, but no more than 45 days' notice, of the annual meeting 
 25.11  by mailing notice to those persons who have requested notice and 
 25.12  by publication in the board's "EQB Monitor." 
 25.13     Sec. 17.  Minnesota Statutes 2000, section 116C.59, 
 25.14  subdivision 1, is amended to read: 
 25.15     Subdivision 1.  [ADVISORY TASK FORCE.] The board may 
 25.16  appoint one or more advisory task forces to assist it in 
 25.17  carrying out its duties.  Task forces appointed to evaluate 
 25.18  sites or routes considered for designation shall be comprised of 
 25.19  as many persons as may be designated by the board, but at least 
 25.20  one representative from each of the following:  Regional 
 25.21  development commissions, counties and municipal corporations and 
 25.22  one town board member from each county in which a site or route 
 25.23  is proposed to be located.  No officer, agent, or employee of a 
 25.24  utility shall serve on an advisory task force.  Reimbursement 
 25.25  for expenses incurred shall be made pursuant to the rules 
 25.26  governing state employees.  The task forces expire as provided 
 25.27  in section 15.059, subdivision 6.  At the time the task force is 
 25.28  appointed, the board shall specify the charge to the task 
 25.29  force.  The task force shall expire upon completion of its 
 25.30  charge, upon designation by the board of alternative sites or 
 25.31  routes to be included in the environmental impact statement, or 
 25.32  upon the specific date identified by the board in the charge, 
 25.33  whichever occurs first.  
 25.34     Sec. 18.  Minnesota Statutes 2000, section 116C.59, 
 25.35  subdivision 4, is amended to read: 
 25.36     Subd. 4.  [SCIENTIFIC ADVISORY TASK FORCE.] The board may 
 26.1   appoint one or more advisory task forces composed of technical 
 26.2   and scientific experts to conduct research and make 
 26.3   recommendations concerning generic issues such as health and 
 26.4   safety, underground routes, double circuiting and long-range 
 26.5   route and site planning.  Reimbursement for expenses incurred 
 26.6   shall be made pursuant to the rules governing reimbursement of 
 26.7   state employees.  The task forces expire as provided in section 
 26.8   15.059, subdivision 6.  The time allowed for completion of a 
 26.9   specific site or route procedure may not be extended to await 
 26.10  the outcome of these generic investigations. 
 26.11     Sec. 19.  Minnesota Statutes 2000, section 116C.60, is 
 26.12  amended to read: 
 26.13     116C.60 [PUBLIC MEETINGS; TRANSCRIPT OF PROCEEDINGS; 
 26.14  WRITTEN RECORDS.] 
 26.15     Meetings of the board, including hearings, shall must be 
 26.16  open to the public.  Minutes shall must be kept of board 
 26.17  meetings and a complete record of public hearings shall be 
 26.18  kept.  All books, records, files, and correspondence of the 
 26.19  board shall must be available for public inspection at any 
 26.20  reasonable time.  The council shall board is also be subject to 
 26.21  chapter 13D. 
 26.22     Sec. 20.  Minnesota Statutes 2000, section 216B.2421, 
 26.23  subdivision 2, is amended to read: 
 26.24     Subd. 2.  [LARGE ENERGY FACILITY.] "Large energy facility" 
 26.25  means: 
 26.26     (1) any electric power generating plant or combination of 
 26.27  plants at a single site with a combined capacity of 80,000 
 26.28  kilowatts or more, or any facility of 50,000 kilowatts or more 
 26.29  which requires oil, natural gas, or natural gas liquids as a 
 26.30  fuel and for which an installation permit has not been applied 
 26.31  for by May 19, 1977 pursuant to Minn. Reg. APC 3(a) and 
 26.32  transmission lines directly associated with the plant that are 
 26.33  necessary to interconnect the plant to the transmission system; 
 26.34     (2) any high voltage transmission line with a capacity of 
 26.35  200 100 kilovolts or more and (i) with more than 50 ten miles 
 26.36  of its length in Minnesota, or (ii) any of its length in 
 27.1   Minnesota and that crosses the state line; or, any high voltage 
 27.2   transmission line with a capacity of 300 kilovolts or more with 
 27.3   more than 25 miles of its length in Minnesota; 
 27.4      (3) any pipeline greater than six inches in diameter and 
 27.5   having more than 50 miles of its length in Minnesota used for 
 27.6   the transportation of coal, crude petroleum or petroleum fuels 
 27.7   or oil or their derivatives; 
 27.8      (4) any pipeline for transporting natural or synthetic gas 
 27.9   at pressures in excess of 200 pounds per square inch with more 
 27.10  than 50 miles of its length in Minnesota; 
 27.11     (5) any facility designed for or capable of storing on a 
 27.12  single site more than 100,000 gallons of liquefied natural gas 
 27.13  or synthetic gas; 
 27.14     (6) any underground gas storage facility requiring permit 
 27.15  pursuant to section 103I.681; 
 27.16     (7) any nuclear fuel processing or nuclear waste storage or 
 27.17  disposal facility; and 
 27.18     (8) any facility intended to convert any material into any 
 27.19  other combustible fuel and having the capacity to process in 
 27.20  excess of 75 tons of the material per hour. 
 27.21     Sec. 21.  Minnesota Statutes 2000, section 216B.2421, is 
 27.22  amended by adding a subdivision to read: 
 27.23     Subd. 4.  [MODIFYING EXISTING LARGE ENERGY FACILITY.] 
 27.24  Refurbishing or upgrading an existing large energy facility 
 27.25  through the replacement or addition of facility components does 
 27.26  not require a certificate of need under section 216B.243, unless 
 27.27  the changes lead to (1) a capacity increase of more than 100 
 27.28  megawatts, or ten percent of existing capacity, whichever is 
 27.29  greater, or (2) operation at more than 50 percent higher voltage.
 27.30     Sec. 22.  Minnesota Statutes 2000, section 216B.243, 
 27.31  subdivision 2, is amended to read: 
 27.32     Subd. 2.  [CERTIFICATE REQUIRED.] (a) Except as provided in 
 27.33  paragraph (b), no large energy facility shall may be sited or 
 27.34  constructed in Minnesota without the issuance of a certificate 
 27.35  of need by the commission pursuant to sections 216C.05 to 
 27.36  216C.30 and this section and consistent with the criteria for 
 28.1   assessment of need. 
 28.2      (b) Notwithstanding paragraph (a), a large energy facility 
 28.3   that is a generation facility of 500 megawatts or less or a 
 28.4   natural gas peaking facility not owned by a public or municipal 
 28.5   utility or cooperative electric association and that is not to 
 28.6   be included in the utility's or association's rate base does not 
 28.7   need a certificate of need under this section. 
 28.8      (c) The commission may not issue a certificate of need for 
 28.9   a generation facility with coal as its primary fuel, unless the 
 28.10  commission finds that the facility implements the most stringent 
 28.11  technology and processes technically achievable, to ensure the 
 28.12  least impact on the state's environment from the facility. 
 28.13     Sec. 23.  Minnesota Statutes 2000, section 216B.243, is 
 28.14  amended by adding a subdivision to read: 
 28.15     Subd. 2a.  [PUBLIC PURPOSE DESIGNATION.] (a) When filing 
 28.16  for a certificate of need under this section, an applicant may 
 28.17  also petition the commission to designate the proposed large 
 28.18  energy facility a public purpose project.  The commission shall 
 28.19  approve or reject the petition at the same time the commission 
 28.20  renders its decision under subdivision 5.  Notwithstanding 
 28.21  section 116C.63 or any other law to the contrary, eminent domain 
 28.22  authority may not be used in constructing a large energy 
 28.23  facility unless the commission designates the facility a public 
 28.24  purpose project.  The value paid for property in the exercise of 
 28.25  eminent domain authority may be structured so as to provide for 
 28.26  the payment of a portion of the revenue derived from the large 
 28.27  energy facility over a period of years, rather than a lump sum 
 28.28  payment at the time the property is taken. 
 28.29     (b) In deciding whether to designate a proposed large 
 28.30  energy facility as a public purpose project, the commission 
 28.31  shall consider whether the proposed facility: 
 28.32     (1) remedies a condition, or set of conditions, that, based 
 28.33  on the utility's most recent forecast or consistent with the 
 28.34  transmission expansion plan of a federally approved regional 
 28.35  transmission organization or regional reliability entity, may 
 28.36  materially limit the adequacy of electric supply, efficiency of 
 29.1   electric service, or reliability of electric service to 
 29.2   Minnesota consumers; 
 29.3      (2) was identified as a critical need by the relevant 
 29.4   regional energy infrastructure planning group; 
 29.5      (3) is consistent with all relevant state goals and 
 29.6   strategies approved by the legislature under section 216B.017; 
 29.7   and 
 29.8      (4) is otherwise in the public interest. 
 29.9      Sec. 24.  Minnesota Statutes 2000, section 216B.243, 
 29.10  subdivision 3, is amended to read: 
 29.11     Subd. 3.  [SHOWING REQUIRED FOR CONSTRUCTION.] No (a) A 
 29.12  proposed large energy facility shall may not be certified for 
 29.13  construction unless the applicant can show that demand for 
 29.14  electricity cannot be met more cost-effectively through energy 
 29.15  conservation and load-management measures and unless the 
 29.16  applicant has otherwise justified its need.  
 29.17     (b) In assessing need, the commission shall evaluate: 
 29.18     (1) the accuracy of the long-range energy demand forecasts 
 29.19  on which the necessity for the facility is based; 
 29.20     (2) the effect of existing or possible energy conservation 
 29.21  programs under sections 216C.05 to 216C.30 and this section or 
 29.22  other federal or state legislation on long-term energy demand; 
 29.23     (3) the relationship of the proposed facility to overall 
 29.24  state and regional energy needs, as described in the most recent 
 29.25  state energy policy and conservation report prepared under 
 29.26  section 216C.18 including consideration of (i) the most recent 
 29.27  state energy security blueprint under section 216B.015, (ii) the 
 29.28  most recent relevant regional energy infrastructure planning 
 29.29  group report under section 216B.019, and (iii) information from 
 29.30  federal and regional reliability organizations, regional 
 29.31  transmission organizations, and other relevant sources; 
 29.32     (4) promotional activities that may have given rise to the 
 29.33  demand for this facility; 
 29.34     (5) socially beneficial uses of the output (3) 
 29.35  environmental and socioeconomic benefits of this facility, 
 29.36  including its uses to protect or enhance environmental quality, 
 30.1   to increase reliability of energy supply in Minnesota and the 
 30.2   region, and to induce future development; 
 30.3      (6) the effects of the facility in inducing future 
 30.4   development; 
 30.5      (7) (4) possible alternatives for satisfying the energy 
 30.6   demand or transmission needs including but not limited to 
 30.7   potential for increased efficiency and upgrading of existing 
 30.8   energy generation and transmission facilities, load management 
 30.9   programs, and distributed generation; 
 30.10     (8) (5) the policies, rules, and regulations of other state 
 30.11  and federal agencies and local governments; and 
 30.12     (9) any (6) feasible combination of energy conservation 
 30.13  improvements, required under section 216B.241, sections 216C.05 
 30.14  to 216C.30, or other available conservation programs that can (i)
 30.15  reasonably replace a significant part or all of the energy to be 
 30.16  provided by the proposed facility, and (ii) compete with it 
 30.17  economically and in terms of reliability; and 
 30.18     (7) whether the proposed large energy facility was 
 30.19  recommended for construction by the relevant regional energy 
 30.20  infrastructure planning group. 
 30.21     Sec. 25.  Minnesota Statutes 2000, section 216B.243, 
 30.22  subdivision 4, is amended to read: 
 30.23     Subd. 4.  [APPLICATION FOR CERTIFICATE; HEARING.] Any 
 30.24  person proposing to construct a large energy facility shall 
 30.25  apply for a certificate of need prior to construction of the 
 30.26  facility.  The application shall must be on forms and in a 
 30.27  manner established by the commission.  In reviewing each 
 30.28  application the commission shall hold at least one public 
 30.29  hearing pursuant to chapter 14.  The public hearing shall must 
 30.30  be held at a location and hour reasonably calculated to be 
 30.31  convenient for the public.  An objective of the public 
 30.32  hearing shall must be to obtain public opinion on the necessity 
 30.33  of granting a certificate of need.  The commission shall 
 30.34  designate a commission employee whose duty shall be to 
 30.35  facilitate citizen participation in the hearing process.  If the 
 30.36  commission and the environmental quality board determine that a 
 31.1   joint hearing on siting and need under this subdivision and 
 31.2   section 116C.57, subdivision 2d, is feasible, more efficient, 
 31.3   and may further the public interest, a joint hearing under those 
 31.4   subdivisions may be held. 
 31.5      Sec. 26.  [INSTRUCTION TO REVISOR.] 
 31.6      The revisor of statutes shall renumber Minnesota Statutes, 
 31.7   section 116C.57, subdivision 6, as section 116C.57, subdivision 
 31.8   9. 
 31.9      Sec. 27.  [REPEALER.] 
 31.10     Minnesota Statutes 2000, sections 116C.55; 116C.57, 
 31.11  subdivisions 3, 5, and 5a; and 116C.67, are repealed. 
 31.12     Sec. 28.  [EFFECTIVE DATE.] 
 31.13     This article is effective the day following final enactment.
 31.14                             ARTICLE 3 
 31.15                       REGULATORY FLEXIBILITY 
 31.16     Section 1.  Minnesota Statutes 2000, section 216B.16, 
 31.17  subdivision 7, is amended to read: 
 31.18     Subd. 7.  [ENERGY COST ADJUSTMENT.] (a) Notwithstanding any 
 31.19  other provision of this chapter, the commission may permit a 
 31.20  public utility to file rate schedules containing provisions for 
 31.21  the automatic adjustment of charges for public utility service 
 31.22  in direct relation to changes in:  (1) federally regulated 
 31.23  wholesale rates for energy delivered through interstate 
 31.24  facilities; (2) direct costs for natural gas delivered; or (3) 
 31.25  costs for fuel used in generation of electricity or the 
 31.26  manufacture of gas. 
 31.27     (b) In reviewing utility fuel purchases under this or any 
 31.28  other provision, the commission shall allow and encourage a 
 31.29  utility to have a combination of measures to manage price 
 31.30  volatility and risk, including but not limited to having an 
 31.31  appropriate share of the utility's supply come from long-term 
 31.32  and medium-term contracts, in order to minimize consumer 
 31.33  exposure to fuel price volatility. 
 31.34     Sec. 2.  [216B.169] [RENEWABLE AND HIGH EFFICIENCY ENERGY 
 31.35  RATE OPTIONS.] 
 31.36     (a) Each public utility, cooperative association, and 
 32.1   municipal utility shall offer its customers, and shall advertise 
 32.2   the offer at least annually, one or more options that allow a 
 32.3   customer to determine that a certain amount of the electricity 
 32.4   generated or purchased on behalf of the customer is (1) 
 32.5   renewable energy as defined in section 216B.2422, subdivision 1, 
 32.6   paragraph (c), or (2) high-efficiency, low-emissions, 
 32.7   distributed generation such as fuel cells and microturbines 
 32.8   fueled by a renewable fuel. 
 32.9      (b) Each public utility shall file an implementation plan 
 32.10  within 90 days of the effective date of this section to 
 32.11  implement paragraph (a).  
 32.12     (c) Rates charged to customers must be calculated using the 
 32.13  utility's or association's cost of acquiring the energy for the 
 32.14  customer and must be (1) the difference between the cost of 
 32.15  generating or purchasing the renewable energy and the cost of 
 32.16  generating or purchasing the same amount of nonrenewable energy; 
 32.17  and (2) distributed on a per kilowatt-hour basis among all 
 32.18  customers who choose to participate in the program.  
 32.19  Implementation of these rate options may reflect a reasonable 
 32.20  amount of lead time necessary to arrange acquisition of the 
 32.21  energy.  
 32.22     (d) If a utility is not able to arrange an adequate supply 
 32.23  of renewable or high-efficiency energy to meet its customers' 
 32.24  demand under this section, the utility must file a report with 
 32.25  the commission detailing its efforts and reasons for its failure.
 32.26     (e) The commission, by order, may establish a program for 
 32.27  tradeable credits for renewable energy under this section. 
 32.28     Sec. 3.  [216B.2411] [CONSERVATION INVESTMENT PROGRAM.] 
 32.29     Subdivision 1.  [DEFINITIONS.] For purposes of this section 
 32.30  and section 216B.16, subdivision 6b, the terms defined in this 
 32.31  subdivision have the meanings given them. 
 32.32     (a) "Commission" means the public utilities commission. 
 32.33     (b) "Commissioner" means the commissioner of commerce. 
 32.34     (c) "Customer facility" means all buildings, structures, 
 32.35  equipment, and installations at a single site. 
 32.36     (d) "Department" means the department of commerce. 
 33.1      (e) "Energy conservation improvement" means the purchase or 
 33.2   installation of a device, method, material, or project: 
 33.3      (1) that reduces consumption of or increases efficiency in 
 33.4   the use of electricity or natural gas, including but not limited 
 33.5   to insulation and ventilation, storm or thermal doors or 
 33.6   windows, caulking and weatherstripping, furnace efficiency 
 33.7   modifications, thermostat or lighting controls, awnings, or 
 33.8   systems to turn off or vary the delivery of energy; 
 33.9      (2) that either (i) creates, converts, or actively uses 
 33.10  energy from renewable sources such as solar, wind, and biomass, 
 33.11  or (ii) recovers energy for reuse, from air or water or other 
 33.12  similar material, provided that the device or method conforms 
 33.13  with national or state performance and quality standards 
 33.14  whenever applicable; 
 33.15     (3) that seeks to provide energy savings through 
 33.16  reclamation or recycling and that is used as part of the 
 33.17  infrastructure of an electric generation, transmission, or 
 33.18  distribution system within the state or a natural gas 
 33.19  distribution system within the state; 
 33.20     (4) that provides research or development of new means of 
 33.21  increasing energy efficiency or conserving energy or research or 
 33.22  development of improvement of existing means of increasing 
 33.23  energy efficiency or conserving energy; or 
 33.24     (5) that either (i) is a renewable energy facility, such as 
 33.25  a facility utilizing agricultural wastes as biomass fuel, or a 
 33.26  methane digester facility associated with livestock feedlots for 
 33.27  the production of energy, the grants for which should be 
 33.28  coordinated with loans under the shared savings loan program 
 33.29  established in section 17.115 to the extent feasible; (ii) 
 33.30  increases a customer's ability to control the amount and 
 33.31  scheduling of energy purchased from a utility, such as through 
 33.32  the installation of a distributed generation facility as 
 33.33  described in section 216B.169; or (iii) allows the utility or 
 33.34  the customer to manage customer load if doing so reduces the 
 33.35  demand for or increases the efficiency of electric services. 
 33.36     (f) "Investments and expenses of a public utility" includes 
 34.1   the investments and expenses incurred by a public utility in 
 34.2   connection with an energy conservation improvement, including 
 34.3   but not limited to: 
 34.4      (1) the differential in interest cost between the market 
 34.5   rate and the rate charged on a no-interest or below-market 
 34.6   interest loan made by a public utility to a customer for the 
 34.7   purchase or installation of an energy conservation improvement; 
 34.8   and 
 34.9      (2) the difference between the utility's cost of purchase 
 34.10  or installation of energy conservation improvements and any 
 34.11  price charged by a public utility to a customer for those 
 34.12  improvements. 
 34.13     (g) "Large electric customer facility" means a customer 
 34.14  facility that imposes a peak electrical demand on an electric 
 34.15  utility's system of not less than 10,000 kilowatts, measured in 
 34.16  the same way as the utility that serves the customer facility 
 34.17  measures electrical demand for billing purposes, and for which 
 34.18  electric services are provided at retail on a single bill by a 
 34.19  utility operating in the state. 
 34.20     (h) "Utility" means a public utility, municipal utility, 
 34.21  electric cooperative association, or any combination of these 
 34.22  authorized under Minnesota law.  
 34.23     Subd. 2.  [INVESTMENT, EXPENDITURE, AND CONTRIBUTION; 
 34.24  PUBLIC UTILITY.] (a) Each public utility shall spend and invest 
 34.25  for energy conservation improvements under this subdivision the 
 34.26  following amounts: 
 34.27     (1) for a public utility that furnishes gas service, 0.5 
 34.28  percent of its annual average gross operating revenues over the 
 34.29  previous five years from service provided in the state; 
 34.30     (2) for a public utility that furnishes electric service, 
 34.31  1.5 percent of its annual average gross operating revenues over 
 34.32  the previous five years from service provided in the state; and 
 34.33     (3) for a public utility that furnishes electric service 
 34.34  and that operates a nuclear-powered electric generating plant 
 34.35  within the state, 2.0 percent of its annual average gross 
 34.36  operating revenues over the previous five years from service 
 35.1   provided in the state. 
 35.2      (b) Load management may only be used to meet the 
 35.3   requirements for energy conservation improvements under this 
 35.4   section if it results in a demonstrable reduction in consumption 
 35.5   of energy.  However, up to five percent of the total amount 
 35.6   required to be spent under this section may be spent on 
 35.7   conservation improvements described in subdivision 1, paragraph 
 35.8   (e), clause (5).  Each public utility subject to this 
 35.9   subdivision may spend and invest annually up to 15 percent of 
 35.10  the total amount required to be spent and invested on energy 
 35.11  conservation improvements under this section by the utility on 
 35.12  research and development projects that meet the definition of 
 35.13  energy conservation improvement in subdivision 1 and that are 
 35.14  funded directly by the public utility. 
 35.15     Subd. 3.  [CONSERVATION IMPROVEMENT BY COOPERATIVE 
 35.16  ASSOCIATION OR MUNICIPALITY.] (a) This subdivision applies to: 
 35.17     (1) a cooperative electric association that generates and 
 35.18  transmits electricity to associations that provide electricity 
 35.19  at retail including a cooperative electric association not 
 35.20  located in this state that serves associations or others in the 
 35.21  state; 
 35.22     (2) a municipality that provides electric service to retail 
 35.23  customers; and 
 35.24     (3) a municipality with gross operating revenues in excess 
 35.25  of $5,000,000 from sales of natural gas to retail customers. 
 35.26     (b) Each cooperative electric association and municipality 
 35.27  subject to this subdivision shall spend and invest for energy 
 35.28  conservation improvements under this subdivision the following 
 35.29  amounts: 
 35.30     (1) for a municipality, 0.5 percent of its annual average 
 35.31  gross operating revenues over the previous five years from the 
 35.32  sale of gas and 1.0 percent of its annual average gross 
 35.33  operating revenues over the previous five years from the sale of 
 35.34  electricity; and 
 35.35     (2) for a cooperative electric association, 1.5 percent of 
 35.36  its annual average gross operating revenues over the previous 
 36.1   five years from service provided in the state. 
 36.2      (c) Each municipality and cooperative association subject 
 36.3   to this subdivision shall identify and implement energy 
 36.4   conservation improvement spending and investments that are 
 36.5   appropriate for the municipality or association.  Municipal 
 36.6   utilities and electric cooperative associations may agree to 
 36.7   form associations or organizations to aggregate their 
 36.8   conservation spending obligations and to jointly provide energy 
 36.9   conservation services to the customers of the municipal 
 36.10  utilities or associations, and shall notify the commissioner in 
 36.11  writing of the formation of such an association or organization. 
 36.12     (d) Each municipality and cooperative electric association 
 36.13  subject to this subdivision may spend and invest annually up to 
 36.14  15 percent of the total amount required to be spent and invested 
 36.15  on energy conservation improvements under this subdivision on 
 36.16  research and development projects that meet the definition of 
 36.17  energy conservation improvement in subdivision 1 and that are 
 36.18  funded directly by the municipality or cooperative electric 
 36.19  association.  
 36.20     (e) Load management may only be used to meet the 
 36.21  requirements of this subdivision if it reduces the demand for or 
 36.22  increases the efficiency of electric services.  
 36.23     (f) Up to five percent of the total amount required to be 
 36.24  spent under this section may be spent on conservation 
 36.25  improvements described in subdivision 1, paragraph (e), clause 
 36.26  (5). 
 36.27     (g) A generation and transmission cooperative electric 
 36.28  association may include as spending and investment required 
 36.29  under this subdivision conservation improvement spending and 
 36.30  investment by cooperative electric associations that provide 
 36.31  electric service at retail to consumers and that are served by 
 36.32  the generation and transmission association. 
 36.33     Subd. 4.  [PROGRAMS.] (a) The commissioner may by rule as 
 36.34  resources allow, or by order, establish standards and criteria 
 36.35  for the provision of energy conservation improvements, including 
 36.36  standard programs, to efficiently and effectively provide energy 
 37.1   conservation services to each utility's energy consumers on a 
 37.2   nondiscriminatory basis and cost-effective manner and to provide 
 37.3   certainty to utilities and associations as to what constitutes 
 37.4   an acceptable energy conservation improvement under this 
 37.5   section.  The list of standard programs may include rebates for 
 37.6   high-efficiency appliances, rebates or subsidies for 
 37.7   high-efficiency lamps, small business energy audits, and 
 37.8   building recommissioning.  A utility may adhere to this list of 
 37.9   programs or may offer other conservation programs not on the 
 37.10  list. 
 37.11     (b) Each public utility shall ensure that a portion of the 
 37.12  money spent on residential conservation improvement programs is 
 37.13  devoted to programs that directly address the needs of renters 
 37.14  and low-income persons unless an insufficient number of 
 37.15  appropriate programs is available. 
 37.16     (c) A utility, a political subdivision, or a nonprofit or 
 37.17  community organization that has suggested an energy conservation 
 37.18  improvement program to a public utility, the attorney general 
 37.19  acting on behalf of consumers and small business interests, or a 
 37.20  utility customer that has suggested a program and is not 
 37.21  represented by the attorney general under section 8.33 may 
 37.22  petition the commission to modify or discontinue a utility 
 37.23  energy conservation improvement program, and the commission may 
 37.24  do so if it determines that the program is not sufficiently cost 
 37.25  effective, does not adequately address the residential 
 37.26  conservation improvement needs of low-income persons, has a 
 37.27  long-range negative effect on one or more classes of customers, 
 37.28  or is otherwise not in the public interest.  The person 
 37.29  petitioning for commission review has the burden of proof.  The 
 37.30  commission shall reject a petition that, on its face, fails to 
 37.31  make a reasonable argument that a program is not in the public 
 37.32  interest. 
 37.33     Subd. 5.  [ENERGY SAVINGS GOALS.] (a) By August 1, 2001, 
 37.34  and every three years thereafter, the commissioner shall develop 
 37.35  energy savings goals: 
 37.36     (1) in kilowatts and kilowatt-hours that each public 
 38.1   utility providing retail electric service in this state can 
 38.2   reasonably be expected to achieve at the level of energy 
 38.3   conservation improvement expenditures required under this 
 38.4   section; and 
 38.5      (2) in cubic feet of natural gas that each public utility 
 38.6   providing retail natural gas service in this state can 
 38.7   reasonably be expected to achieve at the level of conservation 
 38.8   improvement expenditures required under this section.  
 38.9      (b) In consultation with the commissioner, municipal 
 38.10  utilities and cooperative electric associations shall develop 
 38.11  and submit energy savings goals to the commissioner by August 1, 
 38.12  2001, and every three years thereafter.  
 38.13     (c) Municipal utilities and electric cooperative 
 38.14  associations that agree to aggregate their energy conservation 
 38.15  obligations and resources by forming associations or 
 38.16  organizations to provide energy conservation services to their 
 38.17  customers may develop goals for the association or organization, 
 38.18  in lieu of goals for individual members. 
 38.19     Subd. 6.  [OVERVIEW; REVIEW AND AUDIT; PUBLIC 
 38.20  UTILITIES.] (a) By January 1, 2002, and every three years 
 38.21  thereafter, each public utility shall provide the commissioner 
 38.22  with a prospective overview of the utility's planned 
 38.23  conservation activities and the anticipated energy savings on a 
 38.24  triennial basis.  This overview must include a description of 
 38.25  the types of activities, the consumer sectors targeted by each 
 38.26  activity, and the anticipated energy savings and costs of each 
 38.27  activity.  This overview must also indicate, for each type of 
 38.28  activity, how much additional cost-effective conservation is 
 38.29  likely to be achieved in subsequent years.  A public utility may 
 38.30  request the commissioner to approve or reject the utility's plan 
 38.31  prior to implementing the plan.  The commissioner may do so if 
 38.32  resources permit.  
 38.33     (b) By April 1, 2005, and every three years thereafter, 
 38.34  each public utility shall provide a report to the commissioner, 
 38.35  acting on behalf of the commission, summarizing the utility's 
 38.36  conservation activities and energy savings resulting from those 
 39.1   activities under this section.  The public utility shall include 
 39.2   in the report the results of an independent audit performed by 
 39.3   the department or an auditor with experience in the provision of 
 39.4   energy conservation and energy efficiency services approved by 
 39.5   the commissioner and chosen by the utility.  The audit must 
 39.6   specify the actual energy savings or increased efficiency in the 
 39.7   use of energy within the service territory of the utility that 
 39.8   is the result of the spending and investments.  Annually 
 39.9   beginning by April 1, 2003, except for those years a full audit 
 39.10  is due, each utility shall submit a report to the commissioner 
 39.11  detailing the utility's energy conservation activities for the 
 39.12  previous year and provide information regarding the cost 
 39.13  effectiveness of those activities. 
 39.14     (c) The audit provided under paragraph (b) shall evaluate 
 39.15  the cost effectiveness of the utility's conservation programs. 
 39.16  In making this evaluation, the audit shall consider whether the 
 39.17  utility's programs: 
 39.18     (1) fairly address each of the utility's consumer classes 
 39.19  and market sectors; 
 39.20     (2) use accurate and complete data in calculating costs and 
 39.21  energy savings; 
 39.22     (3) identify and target investments and improvements that 
 39.23  have a high potential for saving energy; 
 39.24     (4) indicate an adequate commitment to implementing highly 
 39.25  cost-effective conservation programs; and 
 39.26     (5) comply with the provisions of this section and 
 39.27  associated rules and orders. 
 39.28  An audit must give a negative evaluation if it finds the 
 39.29  utility's overall energy conservation program has not been cost 
 39.30  effective or has failed to satisfy any of the criteria.  Up to 
 39.31  five percent of a utility's conservation spending obligation 
 39.32  under this section may be used for program pre-evaluation, 
 39.33  research and testing, monitoring, and program audit and 
 39.34  evaluation. 
 39.35     (d) Following each submittal of an annual report or a 
 39.36  triennial audit, the commissioner shall issue a report to the 
 40.1   commission as to whether: 
 40.2      (1) the utility's overall conservation program is cost 
 40.3   effective and is in compliance with this section and all 
 40.4   applicable rules or orders; and 
 40.5      (2) the utility has been successful in achieving the energy 
 40.6   savings goals for that utility under subdivision 5. 
 40.7      (e) Following two or more negative evaluations under 
 40.8   paragraph (b), the commission may determine that a utility is 
 40.9   not implementing adequate energy conservation programs.  In that 
 40.10  event, the commission may order the utility to pay into the 
 40.11  energy and conservation account under subdivision 10, up to 50 
 40.12  percent of the utility's or association's conservation spending 
 40.13  obligation under this section.  The commissioner shall select a 
 40.14  third party other than the utility by competitive bid to provide 
 40.15  conservation improvements in the utility's service territory. 
 40.16     Subd. 7.  [OVERVIEW AND PROGRAM EVALUATION; MUNICIPAL AND 
 40.17  COOPERATIVE UTILITIES.] (a) By January 1, 2002, and every three 
 40.18  years thereafter, each municipal utility and electric 
 40.19  cooperative association shall provide the commissioner with a 
 40.20  prospective overview of the utility's or association's planned 
 40.21  conservation activities and the anticipated energy savings on a 
 40.22  triennial basis.  This overview must include a description of 
 40.23  the types of activities, the consumer sectors targeted by each, 
 40.24  and the anticipated energy savings and costs of each activity. 
 40.25  This overview must also indicate, for each type of activity, how 
 40.26  much additional cost-effective conservation is likely to be 
 40.27  achieved in subsequent years. 
 40.28     (b) By February 2, 2002, and every three years thereafter, 
 40.29  each municipal utility or cooperative association shall provide 
 40.30  an evaluation to the commission summarizing the utility's or 
 40.31  association's conservation activities and energy savings 
 40.32  resulting from those activities under this section.  In 
 40.33  consultation with the commissioner, the municipal utility or 
 40.34  cooperative association shall evaluate its energy and capacity 
 40.35  conservation programs, develop plans for future programs, and 
 40.36  report its findings to the commission.  The evaluation must 
 41.1   develop program and performance goals that recognize customer 
 41.2   class, utility service area demographics, cost of program 
 41.3   delivery, regional economic indicators, and utility load shape.  
 41.4   The program evaluation must address: 
 41.5      (1) whether the utility or association has implemented or 
 41.6   is implementing cost-effective energy conservation programs and 
 41.7   specify the energy and capacity savings within the service 
 41.8   territory or association that is the result of conservation 
 41.9   improvement programs, using a list of baseline energy and 
 41.10  capacity savings assumptions developed in consultation with the 
 41.11  department of commerce; 
 41.12     (2) the availability of basic conservation services and 
 41.13  programs to customers; 
 41.14     (3) methodologies that best quantify energy savings, cost 
 41.15  effectiveness, and the potential for cost-effective conservation 
 41.16  improvements; 
 41.17     (4) the value of local administration of conservation 
 41.18  programs in meeting local and statewide needs; 
 41.19     (5) the effect on customer bills; 
 41.20     (6) the role of capacity conservation in meeting utility 
 41.21  planning needs and state energy goals; 
 41.22     (7) the ability of energy conservation programs to avoid 
 41.23  the need for construction of generation facilities and 
 41.24  transmission lines; 
 41.25     (8) whether the utility's or association's programs address 
 41.26  all of the following consumer market sectors:  farm, 
 41.27  residential, commercial, and industrial; and 
 41.28     (9) whether the utility's or association's programs use 
 41.29  accurate and auditable data in calculating costs and energy 
 41.30  savings. 
 41.31     (c) Municipal utilities and electric cooperative 
 41.32  associations that aggregate their energy conservation 
 41.33  obligations and resources by forming associations or 
 41.34  organizations to provide energy conservation services to their 
 41.35  customers may submit overviews, program evaluations, and annual 
 41.36  reports jointly. 
 42.1      Subd. 8.  [ADDITIONAL CONSERVATION SPENDING.] (a) Nothing 
 42.2   in this section prohibits any utility from spending or investing 
 42.3   more for energy conservation improvements than is required in 
 42.4   this section. 
 42.5      (b) The commission may require a public utility to invest 
 42.6   or spend more than is required under this section if the 
 42.7   commission finds that additional investments would be cost 
 42.8   effective, and the utility's most recent forecast projects a 
 42.9   significant supply deficit to meet demand and energy 
 42.10  requirements.  If the commission orders the utility to make 
 42.11  additional conservation investments under this section, the 
 42.12  commission shall provide for financial incentives for these 
 42.13  investments under section 216B.16.  
 42.14     Subd. 9.  [LARGE CUSTOMER OPT-OUT.] (a) The owner of a 
 42.15  large electric customer facility may petition the commissioner 
 42.16  to exempt both electric and gas utilities serving the large 
 42.17  energy customer facility from the investment and expenditure 
 42.18  requirements of subdivision 2 with respect to retail revenues 
 42.19  attributable to the facility.  The petition must contain an 
 42.20  audit by a consultant registered with the department and 
 42.21  selected by the customer, certifying that the customer has 
 42.22  implemented all energy conservation improvements with a ten-year 
 42.23  simple payback or less.  Within five business days of receipt of 
 42.24  a petition that contains this audit, the commissioner shall 
 42.25  either: 
 42.26     (1) grant the petition exempting both electric and gas 
 42.27  utilities serving the large energy customer facility from the 
 42.28  investment and expenditure requirements of this section with 
 42.29  respect to all of the retail revenues attributable to the 
 42.30  facility; or 
 42.31     (2) order a confirming audit of the customer. 
 42.32     (b) The decision to grant the petition or order a 
 42.33  confirming audit is entirely within the discretion of the 
 42.34  commissioner.  The cost of the initial audit must be borne by 
 42.35  the customer. 
 42.36     (c) If the commissioner orders a confirming audit, the 
 43.1   commissioner shall select a contractor from the list maintained 
 43.2   by the department and notify the customer.  
 43.3      (d) If the confirming audit supports the initial audit: 
 43.4      (1) the commissioner shall issue an order granting the 
 43.5   petition within five business days; and 
 43.6      (2) the cost of the confirming audit must be borne by the 
 43.7   electric and gas utilities serving the customer, in relative 
 43.8   proportion to the total retail revenues attributable to the 
 43.9   customer, and deducted from the utility's conservation spending 
 43.10  obligation under this section. 
 43.11     (e) If the confirming audit does not support the initial 
 43.12  audit: 
 43.13     (1) the cost of the confirming audit must be borne by the 
 43.14  customer; and 
 43.15     (2) the commissioner may suspend the consultant that 
 43.16  conducted the initial audit from the list maintained by the 
 43.17  department.  
 43.18     (f) The commissioner shall create, maintain, and publish on 
 43.19  the department's Web site a list of contractors available to 
 43.20  conduct audits under this subdivision.  The commissioner may 
 43.21  spend no more than $20,000 per biennium under this subdivision. 
 43.22     (g) If a petition is filed on or before October 1 of any 
 43.23  year, the order of the commissioner to exempt revenues 
 43.24  attributable to the facility can be effective no earlier than 
 43.25  January 1 of the following year.  The commissioner may, after 
 43.26  investigation, recommend that any exemption granted under this 
 43.27  paragraph be rescinded upon a determination that additional 
 43.28  energy conservation improvements with a simple payback of ten 
 43.29  years or less are available at the large electric customer 
 43.30  facility.  For the purposes of investigations by the 
 43.31  commissioner under this paragraph, the owner of any large 
 43.32  electric customer facility shall, upon request, provide the 
 43.33  commissioner with updated information comparable to that 
 43.34  originally supplied in or with the owner's original petition 
 43.35  under paragraph (a). 
 43.36     (h) For purposes of this section, "gross operating 
 44.1   revenues" do not include revenues from large electric customer 
 44.2   facilities exempted by the commissioner under this subdivision. 
 44.3   A public utility may not spend for or invest in energy 
 44.4   conservation improvements that directly benefit a large electric 
 44.5   customer facility for which the commissioner has issued an 
 44.6   exemption pursuant to this subdivision. 
 44.7      Subd. 10.  [ENERGY AND CONSERVATION ACCOUNT.] (a) Money in 
 44.8   the account is appropriated to the department for programs 
 44.9   designed to meet the energy conservation needs of low-income 
 44.10  persons and to make energy conservation improvements in areas 
 44.11  not adequately served including research and development 
 44.12  projects included in the definition of energy conservation 
 44.13  improvement in subdivision 1. 
 44.14     (b) Using information collected under section 216C.02, 
 44.15  subdivision 1, paragraph (b), the commissioner must, to the 
 44.16  extent possible, allocate enough money to programs for 
 44.17  low-income persons to assure that their needs are being 
 44.18  adequately addressed.  The commissioner must request the 
 44.19  commissioner of finance to transfer money from the account to 
 44.20  the commissioner of economic security for an energy conservation 
 44.21  program for low-income persons.  In establishing programs under 
 44.22  this paragraph, the commissioner must consult political 
 44.23  subdivisions and nonprofit and community organizations, 
 44.24  especially organizations engaged in providing energy and 
 44.25  weatherization assistance to low-income persons.  At least one 
 44.26  program must address the need for energy conservation 
 44.27  improvements in areas in which a high percentage of residents 
 44.28  use fuel oil or propane to fuel their source of home heating. 
 44.29     (c) The commissioner may contract with a political 
 44.30  subdivision, a nonprofit or community organization, a public 
 44.31  utility, a municipality, or a cooperative electric association 
 44.32  to implement its programs under this section.  The commissioner 
 44.33  may provide grants to any person to conduct research and 
 44.34  development projects in accordance with this section. 
 44.35     Subd. 11.  [RECOVERY OF EXPENSES.] (a) The commission shall 
 44.36  allow a public utility to recover expenses resulting from a 
 45.1   conservation improvement program consistent with the 
 45.2   requirements of this section and contributions to the energy and 
 45.3   conservation account, unless the recovery would be inconsistent 
 45.4   with a financial incentive proposal approved by the commission.  
 45.5   In addition, a utility may file annually, or the public 
 45.6   utilities commission may require the utility to file, and the 
 45.7   commission may approve, rate schedules containing provisions for 
 45.8   the automatic adjustment of charges for utility service in 
 45.9   direct relation to changes in the expenses of the utility for 
 45.10  real and personal property taxes, fees, and permits, the amounts 
 45.11  of which the utility cannot control. 
 45.12     (b) A public utility is eligible to file for adjustment for 
 45.13  real and personal property taxes, fees, and permits under this 
 45.14  subdivision only if, in the year previous to the year in which 
 45.15  it files for adjustment, it has spent or invested at least 2.25 
 45.16  percent of its gross revenues from provision of electric 
 45.17  service, excluding gross operating revenues from electric 
 45.18  service provided in the state to large electric customer 
 45.19  facilities for which the commissioner has issued an exemption 
 45.20  under subdivision 9, and 0.75 percent of its gross revenues from 
 45.21  provision of gas service, excluding gross operating revenues 
 45.22  from gas services provided in the state to large electric 
 45.23  customer facilities for which the commissioner has issued an 
 45.24  exemption under subdivision 9, for that year for energy 
 45.25  conservation improvements under this section. 
 45.26     Subd. 12.  [OWNERSHIP OF ENERGY CONSERVATION 
 45.27  IMPROVEMENT.] An energy conservation improvement made to or 
 45.28  installed in a building in accordance with this section, except 
 45.29  systems owned by the utility and designed to turn off, limit, or 
 45.30  vary the delivery of energy, are the exclusive property of the 
 45.31  owner of the building except to the extent that the improvement 
 45.32  is subjected to a security interest in favor of the utility in 
 45.33  case of a loan to the building owner.  The utility has no 
 45.34  liability for loss, damage, or injury caused directly or 
 45.35  indirectly by an energy conservation improvement except for 
 45.36  negligence by the utility in purchase, installation, or 
 46.1   modification of the product. 
 46.2      Subd. 13.  [FEDERAL LAW PROHIBITIONS.] If investments by 
 46.3   public utilities in energy conservation improvements are in any 
 46.4   manner prohibited or restricted by federal law and there is a 
 46.5   provision under which the prohibition or restriction may be 
 46.6   waived, then the commission, the governor, or any other 
 46.7   necessary state agency or officer shall take all necessary and 
 46.8   appropriate steps to secure a waiver with respect to those 
 46.9   public utility investments in energy conservation improvements 
 46.10  included in this section. 
 46.11     Subd. 14.  [EFFICIENT LIGHTING PROGRAM.] (a) Each public 
 46.12  utility, cooperative electric association, and municipal utility 
 46.13  that provides electric service to retail customers shall include 
 46.14  as part of its conservation improvement activities a program to 
 46.15  strongly encourage the use of fluorescent and high intensity 
 46.16  discharge lamps.  The program must include at least a public 
 46.17  information campaign to encourage use of the lamps and proper 
 46.18  management of spent lamps by all customer classifications. 
 46.19     (b) A public utility that provides electric service at 
 46.20  retail to 200,000 or more customers shall establish, either 
 46.21  directly or through contracts with other persons, including lamp 
 46.22  manufacturers, distributors, wholesalers, and retailers and 
 46.23  local government units, a system to collect for delivery to a 
 46.24  reclamation or recycling facility spent fluorescent and 
 46.25  high-intensity discharge lamps from households and from small 
 46.26  businesses as defined in section 645.445 that generate an 
 46.27  average of fewer than ten spent lamps per year. 
 46.28     (c) A collection system must include establishing 
 46.29  reasonably convenient locations for collecting spent lamps from 
 46.30  households and financial incentives sufficient to encourage 
 46.31  spent lamp generators to take the lamps to the collection 
 46.32  locations.  Financial incentives may include coupons for 
 46.33  purchase of new fluorescent or high-intensity discharge lamps, a 
 46.34  cash-back system, or any other financial incentive or group of 
 46.35  incentives designed to collect the maximum number of spent lamps 
 46.36  from households and small businesses that is reasonably feasible.
 47.1      (d) A public utility that provides electric service at 
 47.2   retail to fewer than 200,000 customers, a cooperative electric 
 47.3   association, or a municipal utility that provides electric 
 47.4   service at retail to customers may establish a collection system 
 47.5   under paragraphs (b) and (c) as part of conservation improvement 
 47.6   activities required under this section. 
 47.7      (e) The commissioner of the pollution control agency may 
 47.8   not, unless clearly required by federal law, require a public 
 47.9   utility, cooperative electric association, or municipality that 
 47.10  establishes a household fluorescent and high-intensity discharge 
 47.11  lamp collection system under this section to manage the lamps as 
 47.12  hazardous waste as long as the lamps are managed to avoid 
 47.13  breakage and are delivered to a recycling or reclamation 
 47.14  facility that removes mercury and other toxic materials 
 47.15  contained in the lamps prior to placement of the lamps in solid 
 47.16  waste. 
 47.17     (f) If a utility contracts with a local government unit to 
 47.18  provide a collection system under this subdivision, the contract 
 47.19  must provide for payment to the local government unit of all the 
 47.20  unit's incremental costs of collecting and managing spent lamps. 
 47.21     (g) All the costs incurred by a public utility, cooperative 
 47.22  electric association, or municipal utility for promotion and 
 47.23  collection of fluorescent and high-intensity discharge lamps 
 47.24  under this subdivision constitute conservation improvement 
 47.25  spending under this section. 
 47.26     Sec. 4.  Minnesota Statutes 2000, section 216B.2422, 
 47.27  subdivision 2, is amended to read: 
 47.28     Subd. 2.  [RESOURCE PLAN FILING AND APPROVAL.] A utility 
 47.29  shall file a resource plan with the commission periodically in 
 47.30  accordance with rules adopted by the commission.  The commission 
 47.31  shall approve, reject, or modify the plan of a public utility, 
 47.32  as defined in section 216B.02, subdivision 4, consistent with 
 47.33  the public interest.  In the resource plan proceedings of 
 47.34  all other utilities, the commission's utility may request the 
 47.35  commission to approve or reject the resource plan, and the 
 47.36  commission may do so if the resources of both the commission and 
 48.1   the department permit.  Otherwise, the filing of the plan is 
 48.2   informational only.  If the utility requests the commissioner to 
 48.3   waive the need for a certificate of need under subdivision 6 or 
 48.4   to approve a bidding schedule under subdivision 5, the 
 48.5   commission's order is binding.  Otherwise, the commission's 
 48.6   order shall be is advisory and the order's findings and 
 48.7   conclusions shall constitute prima facie evidence which that may 
 48.8   be rebutted by substantial evidence in all other proceedings.  
 48.9   With respect to utilities other than those defined in section 
 48.10  216B.02, subdivision 4, the commission shall consider the filing 
 48.11  requirements and decisions in any comparable proceedings in 
 48.12  another jurisdiction.  As a part of its resource plan filing, a 
 48.13  utility shall include the least cost plan for meeting 50 and 75 
 48.14  percent of all new and refurbished capacity needs through a 
 48.15  combination of conservation and renewable energy resources. 
 48.16     Sec. 5.  [452.25] [JOINT VENTURES BY UTILITIES.] 
 48.17     Subdivision 1.  [APPLICABILITY.] This section applies to 
 48.18  all home rule charter and statutory cities, except as provided 
 48.19  in section 6. 
 48.20     Subd. 2.  [DEFINITIONS.] For purposes of this section: 
 48.21     (a) "City" means a statutory or home rule charter city, 
 48.22  section 410.015 to the contrary notwithstanding. 
 48.23     (b) "Cooperative association" means a cooperative 
 48.24  association organized under chapter 308A.  
 48.25     (c) "Governing body" means (1) the city council in a city 
 48.26  that operates a municipal utility, or (2) a board, commission, 
 48.27  or body empowered by law, city charter, or ordinance or 
 48.28  resolution of the city council to control and operate the 
 48.29  municipal utility. 
 48.30     (d) "Investor-owned utility" means an entity that provides 
 48.31  utility services to the public under chapter 216B and that is 
 48.32  owned by private persons.  
 48.33     (e) "Municipal power agency" means an organization created 
 48.34  under sections 453.51 to 453.62. 
 48.35     (f) "Municipal utility" means a utility owned, operated, or 
 48.36  controlled by a city to provide utility services. 
 49.1      (g) "Public utility" or "utility" means a provider of 
 49.2   electric or water facilities or services or an entity engaged in 
 49.3   other similar or related operations authorized by law or charter.
 49.4      Subd. 3.  [AUTHORITY.] (a) Upon the approval of its elected 
 49.5   utilities commission or, if there be none, its city council, a 
 49.6   municipal utility may enter into a joint venture with other 
 49.7   municipal utilities, municipal power agencies, cooperative 
 49.8   associations, or investor-owned utilities to provide utility 
 49.9   services.  Retail electric utility services provided by a joint 
 49.10  venture must be within the boundaries of each utility's 
 49.11  exclusive electric service territory as shown on the map of 
 49.12  service territories maintained by the department of commerce.  
 49.13  The terms and conditions of the joint venture are subject to 
 49.14  ratification by the governing bodies of the respective utilities 
 49.15  and may include the formation of a corporate or other separate 
 49.16  legal entity with an administrative and governance structure 
 49.17  independent of the respective utilities. 
 49.18     (b) A corporate or other separate legal entity, if formed: 
 49.19     (1) has the authority and legal capacity and, in the 
 49.20  exercise of the joint venture, the powers, privileges, 
 49.21  responsibilities, and duties authorized by this section; 
 49.22     (2) is subject to the laws and rules applicable to the 
 49.23  organization, internal governance, and activities of the entity; 
 49.24     (3) in connection with its property and affairs and in 
 49.25  connection with property within its control, may exercise any 
 49.26  and all powers that may be exercised by a natural person or a 
 49.27  private corporation or other private legal entity in connection 
 49.28  with similar property and affairs; and 
 49.29     (4) a joint venture that does not include an investor-owned 
 49.30  utility may elect to be deemed a municipal utility or a 
 49.31  cooperative association for purposes of chapter 216B or other 
 49.32  federal or state law regulating utility operations; and 
 49.33     (5) a joint venture that includes an investor-owned utility 
 49.34  must notify the public utilities commission 30 days in advance 
 49.35  of offering services.  Upon a finding by the commission, such 
 49.36  joint venture will be subject to regulation under chapter 216B. 
 50.1      (c) Any corporation, if formed, must comply with section 
 50.2   465.719, subdivisions 9, 10, 11, 12, 13, and 14.  The term 
 50.3   "political subdivision," as it is used in section 465.719, shall 
 50.4   refer to the city council of a city. 
 50.5      Subd. 4.  [RETAIL CUSTOMERS.] Unless the joint venture's 
 50.6   retail electric rates, as defined in section 216B.02, 
 50.7   subdivision 5, of a joint venture that does not include an 
 50.8   investor-owned utility, are approved by the governing body of 
 50.9   each municipal utility or municipal power agency and the board 
 50.10  of directors of each cooperative association that is party to 
 50.11  the joint venture, the retail electric customers of the joint 
 50.12  venture, if their number be more than 25, may elect to become 
 50.13  subject to electric rate regulation by the public utilities 
 50.14  commission as provided in chapter 216B.  The election is subject 
 50.15  to and must be carried out according to the procedures in 
 50.16  section 216B.026 and, for these purposes, each retail electric 
 50.17  customer of the joint venture is deemed a member or stockholder 
 50.18  as referred to in section 216B.026.  
 50.19     Subd. 5.  [POWERS.] (a) A joint venture under this section 
 50.20  has the powers, privileges, responsibilities, and duties of the 
 50.21  separate utilities entering into the joint venture as the joint 
 50.22  venture agreement may provide, including the powers under 
 50.23  paragraph (b), except that: 
 50.24     (1) with respect to retail electric utility services, a 
 50.25  joint venture shall not enlarge or extend the service territory 
 50.26  served by the joint venture by virtue of the authority granted 
 50.27  in sections 216B.44, 216B.45, and 216B.47; 
 50.28     (2) a joint venture may extend service to an existing 
 50.29  connected load of 2,000 kilowatts or more, pursuant to section 
 50.30  216B.42, when the load is outside of the assigned service area 
 50.31  of the joint venture, or of the electric utilities party to the 
 50.32  joint venture, only if the load is already being served by one 
 50.33  of the electric utilities party to the joint venture; and 
 50.34     (3) a privately owned utility, as defined in section 
 50.35  216B.02, may extend service to an existing connected load of 
 50.36  2,000 kilowatts or more, pursuant to section 216B.42, when the 
 51.1   load is located within the assigned service territory of the 
 51.2   joint venture, or of the electric utilities party to the joint 
 51.3   venture, only if the load is already being served by that 
 51.4   privately owned utility. 
 51.5   The limitations of clauses (1) to (3) do not apply if written 
 51.6   consent to the action is obtained from the electric utility 
 51.7   assigned to and serving the affected service territory or 
 51.8   connected load. 
 51.9      (b) Joint venture powers include, but are not limited to, 
 51.10  the authority to: 
 51.11     (1) finance, own, acquire, construct, and operate 
 51.12  facilities necessary to provide utility services to retail 
 51.13  customers of the joint venture, including generation, 
 51.14  transmission, and distribution facilities, and like facilities 
 51.15  used in other utility services; 
 51.16     (2) combine assigned service territories, in whole or in 
 51.17  part, upon notice to, hearing by, and approval of the public 
 51.18  utilities commission; 
 51.19     (3) serve customers in the utilities' service territories 
 51.20  or in the combined service territory; 
 51.21     (4) combine, share, or employ administrative, managerial, 
 51.22  operational, or other staff if combining or sharing will not 
 51.23  degrade safety, reliability, or customer service standards; 
 51.24     (5) provide for joint administrative functions, such as 
 51.25  meter reading and billings; 
 51.26     (6) purchase or sell utility services at wholesale for 
 51.27  resale to customers; 
 51.28     (7) provide conservation programs, other utility programs, 
 51.29  and public interest programs, such as cold weather shut-off 
 51.30  protection and conservation spending programs, as required by 
 51.31  law and rule; and 
 51.32     (8) participate as the parties deem necessary in providing 
 51.33  utility services with other municipal utilities, cooperative 
 51.34  utilities, investor-owned utilities, or other entities, public 
 51.35  or private. 
 51.36     (c) Notwithstanding any contrary provision within this 
 52.1   section, a joint venture formed under this section may engage in 
 52.2   wholesale utility services unless the municipal utility, 
 52.3   municipal power agency, cooperative association, or 
 52.4   investor-owned utility party to the joint venture is prohibited 
 52.5   under current law from conducting that activity; but, in any 
 52.6   case, the joint venture may provide wholesale services to a 
 52.7   municipal utility, a cooperative association, or an 
 52.8   investor-owned utility that is party to the joint venture. 
 52.9      (d) This subdivision does not limit the authority of a 
 52.10  joint venture to exercise rights of eminent domain for other 
 52.11  utility purposes to the same extent as is permitted of those 
 52.12  utilities party to the joint venture. 
 52.13     Subd. 6.  [CONSTRUCTION.] (a) The powers conferred by this 
 52.14  section are in addition to the powers conferred by other law or 
 52.15  charter.  A joint venture under this section, and a municipal 
 52.16  utility with respect to any joint venture under this section, 
 52.17  have the powers necessary to effect the intent and purpose of 
 52.18  this section, including, but not limited to, the expenditure of 
 52.19  public funds and the transfer of real or personal property in 
 52.20  accordance with the terms and conditions of the joint venture 
 52.21  and the joint venture agreement.  This section is complete in 
 52.22  itself with respect to the formation and operation of a joint 
 52.23  venture under this section and with respect to a municipal 
 52.24  utility, a cooperative association, or an investor-owned utility 
 52.25  party to a joint venture related to their creation of and 
 52.26  dealings with the joint venture, without regard to other laws or 
 52.27  city charter provisions that do not specifically address or 
 52.28  refer to this section or a joint venture created under this 
 52.29  section. 
 52.30     (b) This section must not be construed to supersede or 
 52.31  modify: 
 52.32     (1) the power of a city council conferred by charter to 
 52.33  overrule or override any action of a governing body other than 
 52.34  the actions of the joint venture; 
 52.35     (2) chapter 216B; 
 52.36     (3) any referendum requirements applicable to the creation 
 53.1   of a new electric utility by a municipality under section 
 53.2   216B.46 or 216B.465; or 
 53.3      (4) any powers, privileges, or authority or any duties or 
 53.4   obligations of a municipal utility, municipal power agency, or 
 53.5   cooperative association acting as a separate legal entity 
 53.6   without reference to a joint venture created under this section. 
 53.7      Sec. 6.  [EXCEPTION.] 
 53.8      Laws 1996, chapter 300, section 1, as amended by Laws 1997, 
 53.9   chapter 232, section 1, govern joint ventures created under it 
 53.10  and those joint ventures are not governed by this section. 
 53.11     Sec. 7.  [EXEMPTION EXTENDED.] 
 53.12     The commissioner of commerce shall not review the exemption 
 53.13  under Minnesota Statutes, section 216B.241, subdivision 1a, 
 53.14  paragraph (b), of a large electric customer facility, as defined 
 53.15  in Minnesota Statutes, section 216B.241, subdivision 1, 
 53.16  paragraph (g), from the investment and expenditure requirements 
 53.17  of Minnesota Statutes, section 216B.241, subdivision 1a, 
 53.18  paragraph (b), for five years from the date the exemption was 
 53.19  granted, provided the exemption was granted before April 15, 
 53.20  2001.  This provision does not apply if the customer facility's 
 53.21  peak electrical demand exceeds ten percent of the peak 
 53.22  electrical demand of the facility as of the date the exemption 
 53.23  was granted. 
 53.24     Sec. 8.  [EFFECTIVE DATE.] 
 53.25     This article is effective the day following final enactment.
 53.26                             ARTICLE 4
 53.27              INTERCONNECTION OF DISTRIBUTED RESOURCES
 53.28     Section 1.  [216B.68] [DEFINITIONS.] 
 53.29     Subdivision 1.  [SCOPE.] The words and terms used in 
 53.30  sections 216B.68 to 216B.75 have the meanings given them in this 
 53.31  section. 
 53.32     Subd. 2.  [APPLICATION FOR INTERCONNECTION AND PARALLEL 
 53.33  OPERATION.] "Application for interconnection and parallel 
 53.34  operation" with the utility system or application means a 
 53.35  standard form of application developed by the commissioner and 
 53.36  approved by the commission. 
 54.1      Subd. 3.  [COMPANY.] "Company" means an electric utility 
 54.2   operating a distribution system. 
 54.3      Subd. 4.  [ELECTRIC UTILITY.] "Electric utility" means all 
 54.4   electric utilities that own and operate equipment in the state 
 54.5   for furnishing electric service at retail. 
 54.6      Subd. 5.  [CUSTOMER.] "Customer" means any individual 
 54.7   person or entity interconnected to the company's utility system 
 54.8   for the purpose of receiving or exporting electric power from or 
 54.9   to the company's utility system. 
 54.10     Subd. 6.  [DISTRIBUTED GENERATION OR ON-SITE DISTRIBUTED 
 54.11  GENERATION.] "Distributed generation" or "on-site distributed 
 54.12  generation" means an electrical generating facility located at a 
 54.13  customer's point of delivery or point of common coupling of ten 
 54.14  megawatts or less and connected at a voltage less than or equal 
 54.15  to 60 kilovolts that may be connected in parallel operation to 
 54.16  the utility system. 
 54.17     Subd. 7.  [FACILITY.] "Facility" means an electrical 
 54.18  generating installation consisting of one or more on-site 
 54.19  distributed generation units.  The total capacity of a 
 54.20  facility's individual on-site distributed generation units may 
 54.21  exceed ten megawatts; however, no more than ten megawatts of a 
 54.22  facility's capacity will be interconnected at any point in time 
 54.23  at the point of common coupling under this section. 
 54.24     Subd. 8.  [INTERCONNECTION.] "Interconnection" means the 
 54.25  physical connection of distributed generation to the utility 
 54.26  system in accordance with the requirements of this section so 
 54.27  that parallel operation can occur. 
 54.28     Subd. 9.  [INTERCONNECTION AGREEMENT.] "Interconnection 
 54.29  agreement" means the standard form of agreement, developed and 
 54.30  approved by the commission.  The interconnection agreement sets 
 54.31  forth the contractual conditions under which a company and a 
 54.32  customer agree that one or more facilities may be interconnected 
 54.33  with the company's utility system. 
 54.34     Subd. 10.  [PARALLEL OPERATION.] "Parallel operation" means 
 54.35  the operation of on-site distributed generation by a customer 
 54.36  while the customer is connected to the company's utility system. 
 55.1      Subd. 11.  [POINT OF COMMON COUPLING.] "Point of common 
 55.2   coupling" means the point where the electrical conductors of the 
 55.3   company utility system are connected to the customer's 
 55.4   conductors and where any transfer of electric power between the 
 55.5   customer and the utility system takes place, such as switchgear 
 55.6   near the meter. 
 55.7      Subd. 12.  [PRECERTIFIED EQUIPMENT.] "Precertified 
 55.8   equipment" means a specific generating and protective equipment 
 55.9   system or systems that have been certified as meeting the 
 55.10  applicable parts of this section relating to safety and 
 55.11  reliability by an entity approved by the commission. 
 55.12     Subd. 13.  [PRE-INTERCONNECTION 
 55.13  STUDY.] "Pre-interconnection study" means a study or studies 
 55.14  that may be undertaken by a company in response to its receipt 
 55.15  of a completed application for interconnection and parallel 
 55.16  operation with the utility system.  Pre-interconnection studies 
 55.17  may include, but are not limited to, service studies, 
 55.18  coordination studies, and utility system impact studies. 
 55.19     Sec. 2.  [216B.69] [INTERCONNECTION OF ON-SITE DISTRIBUTED 
 55.20  GENERATION.] 
 55.21     Subdivision 1.  [PURPOSE.] The purpose of this section is 
 55.22  to: 
 55.23     (1) establish the terms and conditions that govern the 
 55.24  interconnection and parallel operation of on-site distributed 
 55.25  generation; 
 55.26     (2) provide cost savings and reliability benefits to 
 55.27  customers; 
 55.28     (3) establish technical requirements that will promote the 
 55.29  safe and reliable parallel operation of on-site distributed 
 55.30  generation resources; 
 55.31     (4) enhance both the reliability of electric service and 
 55.32  economic efficiency in the production and consumption of 
 55.33  electricity; and 
 55.34     (5) promote the use of distributed resources in order to 
 55.35  provide electric system benefits during periods of capacity 
 55.36  constraints. 
 56.1      Subd. 2.  [DISTRIBUTED GENERATION; GENERIC PROCEEDING.] (a) 
 56.2   The commission shall initiate a proceeding within 30 days of the 
 56.3   effective date of this section, to establish, by order, generic 
 56.4   standards for utility tariffs for the interconnection and 
 56.5   parallel operation of distributed generation of no more than ten 
 56.6   megawatts of interconnected capacity.  The commission shall 
 56.7   ensure that these standards are, and continue to be, consistent 
 56.8   with federal requirements and any distributed generation 
 56.9   interconnection operational and safety standards adopted by the 
 56.10  institute of electrical and electronics engineers, and must: 
 56.11     (1) provide for the low-cost, safe, and standardized 
 56.12  interconnection of facilities fueled by natural gas, by a 
 56.13  renewable fuel, by another similarly clean fuel, or by a 
 56.14  combination of these fuels, which may include, but are not 
 56.15  limited to, fuel cells, microturbines, wind turbines, or solar 
 56.16  modules; 
 56.17     (2) take into account differing system requirements and 
 56.18  hardware, as well as the overall demand load requirements of 
 56.19  individual utilities; 
 56.20     (3) encourage and compensate for the addition of 
 56.21  distributed generation power resources while reducing the cost 
 56.22  to the utility's customers for energy, capacity, transmission, 
 56.23  and distribution; 
 56.24     (4) minimize and avoid increases in the rates of other 
 56.25  customers on the utility's system; 
 56.26     (5) allow for reasonable terms and conditions, consistent 
 56.27  with the cost and operating characteristics of the various 
 56.28  technologies, so that a utility can reasonably be assured of the 
 56.29  reliable, safe, and efficient operation of the interconnected 
 56.30  equipment; 
 56.31     (6) ensure that backup power, supplemental power, and 
 56.32  maintenance power are available to all customers and customer 
 56.33  classes that desire this service; 
 56.34     (7) establish a standard interconnection agreement that 
 56.35  sets forth the contractual conditions under which a company and 
 56.36  a customer agree that one or more facilities may be 
 57.1   interconnected with the company's utility system; and 
 57.2      (8) establish a standard application for interconnection 
 57.3   and parallel operation with the utility system. 
 57.4      (b) The commission may develop financial incentives based 
 57.5   on a public utility's performance in encouraging residential and 
 57.6   small business customers to participate in on-site generation. 
 57.7      Subd. 3.  [DISTRIBUTED GENERATION TARIFF.] Within 90 days 
 57.8   of the issuance of an order under subdivision 2: 
 57.9      (1) each public utility providing electric service at 
 57.10  retail shall file a distributed generation tariff consistent 
 57.11  with that order, for commission approval or approval with 
 57.12  modification; and 
 57.13     (2) each municipal utility and cooperative electric 
 57.14  association shall adopt a distributed generation tariff that 
 57.15  addresses the issues included in the commission's order. 
 57.16     Sec. 3.  [216B.70] [DISCONNECTION AND RECONNECTION.] 
 57.17     Subdivision 1.  [WHEN DISCONNECTION ALLOWED.] A utility may 
 57.18  disconnect a distributed generation unit from the utility system 
 57.19  if: 
 57.20     (1) the interconnection agreement with a customer expires 
 57.21  or terminates, in accordance with the terms of the agreement; 
 57.22     (2) the facility is not in compliance with the technical 
 57.23  requirements specified by the commissioner; 
 57.24     (3) continued interconnection will endanger persons or 
 57.25  property; or 
 57.26     (4) written notice is provided at least seven business days 
 57.27  prior to a service interruption for routine maintenance, 
 57.28  repairs, and utility system modifications. 
 57.29     Subd. 2.  [INCREMENTAL DEMAND CHARGES.] During the term of 
 57.30  an interconnection agreement, a utility may require that a 
 57.31  customer disconnect its distributed generation unit or take it 
 57.32  off-line as a result of utility system conditions.  The company 
 57.33  may not assess the customer incremental demand charges arising 
 57.34  from disconnecting the distributed generator as directed by the 
 57.35  company during these periods. 
 57.36     Sec. 4.  [216B.71] [PRE-INTERCONNECTION STUDIES FOR 
 58.1   NONNETWORK INTERCONNECTION OF DISTRIBUTED GENERATION.] 
 58.2      Subdivision 1.  [STUDIES.] A utility may conduct a service 
 58.3   study, coordination study, or utility system impact study prior 
 58.4   to interconnection of a distributed generation facility.  When a 
 58.5   study is deemed necessary, the scope of the study must be based 
 58.6   on the characteristics of the particular distributed generation 
 58.7   facility to be interconnected and the utility's system at the 
 58.8   specific proposed location.  At the customer's choice, a study 
 58.9   related to interconnection of distributed generation on the 
 58.10  customer's premises may be conducted by a qualified third party 
 58.11  jointly selected by the utility and the customer. 
 58.12     Subd. 2.  [CUSTOMER FEE.] A utility generation facility not 
 58.13  described in subdivision 1 may charge a customer a fee to offset 
 58.14  its costs incurred in the conduct of a pre-interconnection study.
 58.15     Subd. 3.  [WHEN UTILITY CONDUCTS STUDY.] When a utility 
 58.16  conducts an interconnection study, paragraphs (a) to (d) apply: 
 58.17     (a) The conduct of the pre-interconnection study may not 
 58.18  take more than four weeks. 
 58.19     (b) A utility shall prepare written reports of the study 
 58.20  findings and make them available to the customer. 
 58.21     (c) The study must consider both the costs incurred and the 
 58.22  benefits realized as a result of the interconnection of 
 58.23  distributed generation to the company's utility system. 
 58.24     (d) The utility shall provide the customer with an estimate 
 58.25  of the study cost before the utility initiates the study. 
 58.26     Sec. 5.  [216B.72] [PRE-INTERCONNECTION STUDIES FOR NETWORK 
 58.27  INTERCONNECTION OF DISTRIBUTED GENERATION.] 
 58.28     Subdivision 1.  [NOTICE AND FEES.] Prior to charging a 
 58.29  pre-interconnection study fee for a network interconnection of 
 58.30  distributed generation, a utility shall first advise the 
 58.31  customer of the potential problems associated with 
 58.32  interconnection of distributed generation with its network 
 58.33  system.  
 58.34     Subd. 2.  [REQUIREMENTS WHEN UTILITY CONDUCTS STUDY.] When 
 58.35  a utility conducts an interconnection study, paragraphs (a) to 
 58.36  (d) apply: 
 59.1      (a) The conduct of a pre-interconnection study may not take 
 59.2   more than four weeks. 
 59.3      (b) A utility shall prepare written reports of the study 
 59.4   findings and make them available to the customer. 
 59.5      (c) The study must consider both the costs incurred and the 
 59.6   benefits realized as a result of the interconnection of 
 59.7   distributed generation to the utility's system. 
 59.8      (d) The utility shall provide the customer with an estimate 
 59.9   of the study cost before the utility initiates the study. 
 59.10     Sec. 6.  [216B.73] [EQUIPMENT PRECERTIFICATION.] 
 59.11     (a) The commissioner may approve one or more entities that 
 59.12  shall precertify equipment as described under this section. 
 59.13     (b) Testing organizations or facilities capable of 
 59.14  analyzing the function, control, and protective systems of 
 59.15  distributed generation units may request to be certified as 
 59.16  testing organizations. 
 59.17     (c) Distributed generation units that are certified to be 
 59.18  in compliance by an approved testing facility or organization 
 59.19  must be installed on a company utility system in accordance with 
 59.20  an approved interconnection control and protection scheme 
 59.21  without further review of their design by the utility. 
 59.22     Sec. 7.  [216B.74] [TIME FOR PROCESSING APPLICATIONS FOR 
 59.23  INTERCONNECTION.] 
 59.24     (a) The interconnection of distributed generation to the 
 59.25  utility system must take place within the schedules described in 
 59.26  paragraphs (b) to (f): 
 59.27     (b) For a facility with precertified equipment, 
 59.28  interconnection must take place within four weeks of the 
 59.29  utility's receipt of a completed interconnection application. 
 59.30     (c) For facilities without precertified equipment, 
 59.31  connection must take place within six weeks of the utility's 
 59.32  receipt of a completed application. 
 59.33     (d) If interconnection of a particular facility will 
 59.34  require substantial capital upgrades to the utility system, the 
 59.35  company shall provide the customer an estimate of the schedule 
 59.36  and the customer's cost for the upgrade.  If the customer 
 60.1   desires to proceed with the upgrade, the customer and the 
 60.2   company shall enter into a contract for the completion of the 
 60.3   upgrade.  The interconnection must take place no later than two 
 60.4   weeks following the completion of the upgrade.  The utility 
 60.5   shall employ best reasonable efforts to complete the system 
 60.6   upgrade in the shortest time reasonably practical. 
 60.7      (e) A utility shall use best reasonable efforts to 
 60.8   interconnect facilities within the time frames described in this 
 60.9   section.  If in a particular instance, a utility determines that 
 60.10  it cannot interconnect a facility within the time frames stated 
 60.11  in this section, it must notify the applicant in writing of that 
 60.12  fact.  The notification must identify any reasons 
 60.13  interconnection could not be performed in accordance with the 
 60.14  schedule and provide an estimated date for interconnection. 
 60.15     (f) Applications for interconnection and parallel operation 
 60.16  of distributed generation must be processed by the utility in a 
 60.17  nondiscriminatory manner and in the order that they are 
 60.18  received.  It is recognized that certain applications may 
 60.19  require minor modifications while they are being reviewed by the 
 60.20  utility.  These minor modifications to a pending application do 
 60.21  not require that it be considered incomplete and treated as a 
 60.22  new or separate application. 
 60.23     Sec. 8.  [216B.75] [REPORTING REQUIREMENTS.] 
 60.24     (a) Each electric utility shall maintain records concerning 
 60.25  applications received for interconnection and parallel operation 
 60.26  of distributed generation.  The records must include the date 
 60.27  each application is received, documents generated in the course 
 60.28  of processing each application, correspondence regarding each 
 60.29  application, and the final disposition of each application.  
 60.30     (b) As part of the reporting requirement under section 
 60.31  216C.052, subdivision 4, every electric utility shall file with 
 60.32  the reliability administrator a distributed generation 
 60.33  interconnection report for the preceding calendar year that 
 60.34  identifies each distributed generation facility interconnected 
 60.35  with the utility's distribution system.  The report must list 
 60.36  the new distributed generation facilities interconnected with 
 61.1   the system since the previous year's report, any distributed 
 61.2   generation facilities no longer interconnected with the 
 61.3   utility's system since the previous report, the capacity of each 
 61.4   facility, and the feeder or other point on the company's utility 
 61.5   system where the facility is connected.  The annual report must 
 61.6   also identify all applications for interconnection received 
 61.7   during the previous one-year period, and the disposition of the 
 61.8   applications. 
 61.9      Sec. 9.  [EFFECTIVE DATE.] 
 61.10     This article is effective the day following final enactment.
 61.11                             ARTICLE 5 
 61.12                       CONFORMING AMENDMENTS 
 61.13     Section 1.  Minnesota Statutes 2000, section 116C.61, 
 61.14  subdivision 1, is amended to read: 
 61.15     Subdivision 1.  [REGIONAL, COUNTY AND LOCAL ORDINANCES, 
 61.16  RULES, REGULATIONS; PRIMARY RESPONSIBILITY AND REGULATION OF 
 61.17  SITE DESIGNATION, IMPROVEMENT, AND USE.] To assure the paramount 
 61.18  and controlling effect of the provisions herein this section 
 61.19  over other state agencies,; regional, county, and local 
 61.20  governments,; and special purpose government districts, the 
 61.21  issuance of a certificate of site compatibility permit or 
 61.22  transmission line construction route permit and subsequent 
 61.23  purchase and use of such site or route locations for large 
 61.24  electric power generating plant and high voltage transmission 
 61.25  line purposes shall be is the sole site approval required to be 
 61.26  obtained by the utility.  Such certificate or The permit shall 
 61.27  supersede supersedes and preempt all preempts any zoning, 
 61.28  building, or land use rules, regulations, or ordinances 
 61.29  promulgated by any regional, county, local, and special purpose 
 61.30  government. 
 61.31     Sec. 2.  Minnesota Statutes 2000, section 116C.62, is 
 61.32  amended to read: 
 61.33     116C.62 [IMPROVEMENT OF SITES AND ROUTES.] 
 61.34     Utilities which that have acquired a site or route in 
 61.35  accordance with sections 116C.51 to 116C.69 may proceed to 
 61.36  construct or improve the site or route for the intended purposes 
 62.1   at any time, subject to section 116C.61, subdivision 2,; 
 62.2   provided that, if the construction and improvement commences 
 62.3   more than has not commenced within four years after a 
 62.4   certificate or permit for the site or route has been issued, 
 62.5   then the utility must certify to the board that the site or 
 62.6   route continues to meet the conditions upon which the 
 62.7   certificate of site compatibility or transmission line 
 62.8   construction permit was issued. 
 62.9      Sec. 3.  Minnesota Statutes 2000, section 116C.64, is 
 62.10  amended to read: 
 62.11     116C.64 [FAILURE TO ACT.] 
 62.12     If the board fails to act within the times specified in 
 62.13  section 116C.57, the applicant or any affected utility person 
 62.14  may seek an order of the district court requiring the board to 
 62.15  designate or refuse to designate a site or route. 
 62.16     Sec. 4.  Minnesota Statutes 2000, section 116C.645, is 
 62.17  amended to read: 
 62.18     116C.645 [REVOCATION OR SUSPENSION.] 
 62.19     A site certificate permit or construction route permit may 
 62.20  be revoked or suspended by the board after adequate notice of 
 62.21  the alleged grounds for revocation or suspension and a full and 
 62.22  fair hearing in which the affected utility has an opportunity to 
 62.23  confront any witness and respond to any evidence against it and 
 62.24  to present rebuttal or mitigating evidence upon a finding by the 
 62.25  board of: 
 62.26     (1) any false statement knowingly made in the application 
 62.27  or in accompanying statements or studies required of the 
 62.28  applicant, if a true statement would have warranted a change in 
 62.29  the board's findings; 
 62.30     (2) failure to comply with material conditions of the site 
 62.31  certificate or construction permit, or failure to maintain 
 62.32  health and safety standards; or 
 62.33     (3) any material violation of the provisions of sections 
 62.34  116C.51 to 116C.69, any rule promulgated pursuant thereto 
 62.35  adopted under these sections, or any order of the board. 
 62.36     Sec. 5.  Minnesota Statutes 2000, section 116C.65, is 
 63.1   amended to read: 
 63.2      116C.65 [JUDICIAL REVIEW.] 
 63.3      Any utility applicant, party, or person aggrieved by the 
 63.4   issuance of a certificate site or route permit or emergency 
 63.5   certificate of site compatibility or transmission line 
 63.6   construction permit from the board or a certification of 
 63.7   continuing suitability filed by a utility with the board or by a 
 63.8   final order in accordance with any rules promulgated adopted by 
 63.9   the board, may appeal to the court of appeals in accordance with 
 63.10  chapter 14.  The appeal shall must be filed within 60 days after 
 63.11  the publication in the State Register of notice of the issuance 
 63.12  of the certificate or permit by the board or certification filed 
 63.13  with the board or the filing of any final order by the board.  
 63.14     Sec. 6.  Minnesota Statutes 2000, section 116C.66, is 
 63.15  amended to read: 
 63.16     116C.66 [RULES.] 
 63.17     (a) The board, in order to give effect to the purposes of 
 63.18  sections 116C.51 to 116C.69, shall prior to July 1, 1978, may 
 63.19  adopt rules consistent with sections 116C.51 to 116C.69, 
 63.20  including promulgation adoption of site and route designation 
 63.21  criteria,; the description of the information to be furnished by 
 63.22  the utilities,; establishment of minimum guidelines for public 
 63.23  participation in the development, revision, and enforcement of 
 63.24  any rule, plan, or program established by the board,; procedures 
 63.25  for the revocation or suspension of a construction permit or a 
 63.26  certificate of site compatibility,; the procedure and timeliness 
 63.27  for proposing alternative routes and sites,; and route exemption 
 63.28  criteria and procedures. 
 63.29     No (b) A rule adopted by the board shall may not grant 
 63.30  priority to state-owned wildlife management areas over 
 63.31  agricultural lands in the designation of route-avoidance areas. 
 63.32     (c) The provisions of chapter 14 shall apply to the appeal 
 63.33  of rules adopted by the board to the same extent as it applies 
 63.34  to the review of rules adopted by any other agency of state 
 63.35  government. 
 63.36     (d) The chief administrative law judge shall, prior to 
 64.1   January 1, 1978, adopt procedural rules for public hearings 
 64.2   relating to the site and route designation process and to the 
 64.3   route exemption process.  The rules shall must attempt to 
 64.4   maximize citizen participation in these processes. 
 64.5      Sec. 7.  Minnesota Statutes 2000, section 116C.69, is 
 64.6   amended to read: 
 64.7      116C.69 [BIENNIAL REPORT; APPLICATION FEES; APPROPRIATION; 
 64.8   FUNDING.] 
 64.9      Subdivision 1.  [BIENNIAL REPORT.] Before November 15 of 
 64.10  each even-numbered year the board shall prepare and submit to 
 64.11  the legislature a report of its operations, activities, 
 64.12  findings, and recommendations concerning sections 116C.51 to 
 64.13  116C.69.  The report shall also contain information on the 
 64.14  board's biennial expenditures, its proposed budget for the 
 64.15  following biennium, and the amounts paid in certificate and 
 64.16  permit application fees pursuant to subdivisions 2 and 2a and in 
 64.17  assessments pursuant to subdivision 3 this section.  The 
 64.18  proposed budget for the following biennium shall be is subject 
 64.19  to legislative review. 
 64.20     Subd. 2.  [SITE APPLICATION FEE.] Every applicant for a 
 64.21  site certificate permit shall pay to the board a fee in an 
 64.22  amount equal to $500 for each $1,000,000 of production plant 
 64.23  investment in the proposed installation as defined in the 
 64.24  Federal Power Commission Uniform System of Accounts.  The board 
 64.25  shall specify the time and manner of payment of the fee.  If any 
 64.26  single payment requested by the board is in excess of 25 percent 
 64.27  of the total estimated fee, the board shall show that the excess 
 64.28  is reasonably necessary.  The applicant shall pay within 30 days 
 64.29  of notification any additional fees reasonably necessary for 
 64.30  completion of the site evaluation and designation process by the 
 64.31  board.  In no event shall The total fees required of the 
 64.32  applicant under this subdivision must never exceed an amount 
 64.33  equal to 0.001 of said the production plant investment (, which 
 64.34  equals $1,000 for each $1,000,000).  All money received pursuant 
 64.35  to under this subdivision shall must be deposited in a special 
 64.36  account.  Money in the account is appropriated to the board to 
 65.1   pay expenses incurred in processing applications 
 65.2   for certificates site permits in accordance with sections 
 65.3   116C.51 to 116C.69 and in the event, if the expenses are less 
 65.4   than the fee paid, to refund the excess to the applicant.  
 65.5      Subd. 2a.  [ROUTE APPLICATION FEE.] Every applicant for a 
 65.6   transmission line construction route permit shall pay to the 
 65.7   board a base fee of $35,000 plus a fee in an amount equal to 
 65.8   $1,000 per mile length of the longest proposed route.  The board 
 65.9   shall specify the time and manner of payment of the fee.  If any 
 65.10  single payment requested by the board is in excess of 25 percent 
 65.11  of the total estimated fee, the board shall show that the excess 
 65.12  is reasonably necessary.  In the event If the actual cost of 
 65.13  processing an application up to the board's final decision to 
 65.14  designate a route exceeds the above this fee schedule, the board 
 65.15  may assess the applicant any additional fees necessary to cover 
 65.16  the actual costs, not to exceed an amount equal to $500 per mile 
 65.17  length of the longest proposed route.  All money received 
 65.18  pursuant to under this subdivision shall must be deposited in a 
 65.19  special account.  Money in the account is appropriated to the 
 65.20  board to pay expenses incurred in processing applications for 
 65.21  construction route permits in accordance with sections 116C.51 
 65.22  to 116C.69 and in the event, if the expenses are less than the 
 65.23  fee paid, to refund the excess to the applicant.  
 65.24     Subd. 3.  [FUNDING; ASSESSMENT.] (a) The board shall 
 65.25  finance its base line studies, general environmental studies, 
 65.26  development of criteria, inventory preparation, monitoring of 
 65.27  conditions placed on site certificates and construction route 
 65.28  permits, and all other work, other than specific site and route 
 65.29  designation, from an assessment made quarterly, at least 30 days 
 65.30  before the start of each quarter, by the board against all 
 65.31  utilities with annual retail kilowatt-hour sales greater than 
 65.32  4,000,000 kilowatt-hours in the previous calendar year.  
 65.33     (b) Each share shall must be determined as follows: 
 65.34     (1) the ratio that the annual retail kilowatt-hour sales in 
 65.35  the state of each utility bears to the annual total retail 
 65.36  kilowatt-hour sales in the state of all these utilities, 
 66.1   multiplied by 0.667,; plus 
 66.2      (2) the ratio that the annual gross revenue from retail 
 66.3   kilowatt-hour sales in the state of each utility bears to the 
 66.4   annual total gross revenues from retail kilowatt-hour sales in 
 66.5   the state of all these utilities, multiplied by 0.333, as 
 66.6   determined by the board. 
 66.7      (c) The assessment shall must be credited to the special 
 66.8   revenue fund and shall be paid to the state treasury within 30 
 66.9   days after receipt of the bill, which shall constitute notice of 
 66.10  said the assessment and its demand of payment thereof. 
 66.11     (d) The total amount which that may be assessed to the 
 66.12  several utilities under the authority of this subdivision shall 
 66.13  may not exceed the sum of the annual budget of the board for 
 66.14  carrying out the purposes of this subdivision. 
 66.15     (e) The assessment for the second quarter of each fiscal 
 66.16  year shall must be adjusted to compensate for the amount by 
 66.17  which actual expenditures by the board for the preceding fiscal 
 66.18  year were more or less than the estimated expenditures 
 66.19  previously assessed. 
 66.20     Sec. 8.  [INSTRUCTION TO REVISOR.] 
 66.21     (a) The revisor of statutes shall renumber Minnesota 
 66.22  Statutes, section 116C.69, subdivision 1, as Minnesota Statutes, 
 66.23  section 116C.681. 
 66.24     (b) The revisor of statutes shall change all references as 
 66.25  appropriate from Minnesota Statutes, section 216B.241 to 
 66.26  Minnesota Statutes, section 216B.2411, including references to 
 66.27  appropriate subdivisions, if known, in this act and in Minnesota 
 66.28  Statutes, chapters 216A, 216B, and 216C, and in the Minnesota 
 66.29  Rules associated with those chapters. 
 66.30     Sec. 9.  [EFFECTIVE DATE.] 
 66.31     This article is effective the day following final enactment.
 66.32                             ARTICLE 6
 66.33                      MISCELLANEOUS PROVISIONS
 66.34     Section 1.  Minnesota Statutes 2000, section 216A.03, 
 66.35  subdivision 3a, is amended to read: 
 66.36     Subd. 3a.  [POWERS AND DUTIES OF CHAIR.] The chair shall be 
 67.1   is the principal executive officer of the commission and shall 
 67.2   preside at meetings of the commission.  The responsibilities of 
 67.3   the chair shall organize include: 
 67.4      (1) organizing the work of the commission and may make; 
 67.5      (2) making assignments to commission members, appoint 
 67.6   committees and give as appropriate; 
 67.7      (3) appointing subcommittees; 
 67.8      (4) giving direction to the commission staff through the 
 67.9   executive secretary subject to the approval of the commission.; 
 67.10     (5) supervising the work of the executive secretary; and 
 67.11     (6) in coordination with the executive secretary, 
 67.12  participating in employment and termination decisions, including 
 67.13  representing the commission in grievance proceedings; addressing 
 67.14  employee complaints and grievances; developing and implementing 
 67.15  the agency budget; testifying before legislative committees and 
 67.16  working with legislators as requested; determining agency-wide 
 67.17  training needs and initiatives; implementing computer technology 
 67.18  updates; administering and implementing relations with the 
 67.19  department of commerce, the office of the attorney general, and 
 67.20  other agencies; and developing and implementing strategies for 
 67.21  the commission to adapt to rapid changes in the industries the 
 67.22  commission oversees. 
 67.23     Sec. 2.  Minnesota Statutes 2000, section 216B.095, is 
 67.24  amended to read: 
 67.25     216B.095 [DISCONNECTION DURING COLD WEATHER.] 
 67.26     The commission shall amend its rules governing 
 67.27  disconnection of residential utility customers who are unable to 
 67.28  pay for utility service during cold weather to include the 
 67.29  following: 
 67.30     (1) coverage of customers whose household income is less 
 67.31  than 185 percent of the federal poverty level 50 percent of the 
 67.32  state median income; 
 67.33     (2) a requirement that a customer who pays the utility at 
 67.34  least ten percent of the customer's income or the full amount of 
 67.35  the utility bill, whichever is less, in a cold weather month 
 67.36  cannot be disconnected during that month; 
 68.1      (3) that the ten percent figure in clause (2) must be 
 68.2   prorated between energy providers proportionate to each 
 68.3   provider's share of the customer's total energy costs where the 
 68.4   customer receives service from more than one provider; 
 68.5      (4) that a customer's household income does not include any 
 68.6   amount received for energy assistance; 
 68.7      (5) (4) verification of income by the local energy 
 68.8   assistance provider or the utility, unless the customer is 
 68.9   automatically eligible for protection against disconnection as a 
 68.10  recipient of any form of public assistance, including energy 
 68.11  assistance, that uses income eligibility in an amount at or 
 68.12  below the income eligibility in clause (1); and 
 68.13     (6) (5) a requirement that the customer receive, from the 
 68.14  local energy assistance provider or other entity, budget 
 68.15  counseling and referral referrals to energy assistance programs, 
 68.16  weatherization, conservation, or other programs likely to reduce 
 68.17  the customer's consumption of energy bills; 
 68.18     (6) a requirement that customers who have demonstrated an 
 68.19  inability to pay on forms for such purposes provided by the 
 68.20  utility, and who make reasonably timely payments to the utility 
 68.21  under a payment plan that considers the financial resources of 
 68.22  the household, cannot be disconnected from utility services from 
 68.23  October 15 to April 15.  A customer who is receiving energy 
 68.24  assistance is deemed to have demonstrated an inability to pay. 
 68.25  For the purpose of clause (2), the "customer's income" means the 
 68.26  actual monthly income of the customer except for a customer who 
 68.27  is normally employed only on a seasonal basis and whose annual 
 68.28  income is over 135 percent of the federal poverty level, in 
 68.29  which case the customer's income is or the average monthly 
 68.30  income of the customer computed on an annual calendar year 
 68.31  basis, whichever is less, and does not include any amount 
 68.32  received for energy assistance. 
 68.33     Sec. 3.  Minnesota Statutes 2000, section 216B.097, 
 68.34  subdivision 1, is amended to read: 
 68.35     Subdivision 1.  [APPLICATION; NOTICE TO RESIDENTIAL 
 68.36  CUSTOMER.] (a) A municipal utility or a cooperative electric 
 69.1   association must not disconnect the utility service of a 
 69.2   residential customer during the period between October 15 and 
 69.3   April 15 if the disconnection affects the primary heat source 
 69.4   for the residential unit when the following conditions are met: 
 69.5      (1) the disconnection would occur during the period between 
 69.6   October 15 and April 15; 
 69.7      (2) (1) the customer has declared inability to pay on forms 
 69.8   provided by the utility.  For the purpose of this clause, a 
 69.9   customer that is receiving energy assistance is deemed to have 
 69.10  demonstrated an inability to pay; 
 69.11     (3) (2) the household income of the customer is less than 
 69.12  185 percent of the federal poverty level, as documented by the 
 69.13  customer to the utility; and 50 percent of the state median 
 69.14  income; 
 69.15     (3) verification of income may be conducted by the local 
 69.16  energy assistance provider or the utility, unless the customer 
 69.17  is automatically eligible for protection against disconnection 
 69.18  as a recipient of any form of public assistance, including 
 69.19  energy assistance, that uses income eligibility in an amount at 
 69.20  or below the income eligibility in clause (2); 
 69.21     (4) the customer's a customer whose account is current for 
 69.22  the billing period immediately prior to October 15 or the 
 69.23  customer has entered who, at any time, enters into a payment 
 69.24  schedule that considers the financial resources of the household 
 69.25  and is reasonably current with payments under the schedule; and 
 69.26     (5) the customer receives referrals to energy assistance 
 69.27  programs, and weatherization, conservation, or other programs to 
 69.28  reduce the customer's energy bills. 
 69.29     (b) A municipal utility or a cooperative electric 
 69.30  association must, between August 15 and October 15 of each year, 
 69.31  notify all residential customers of the provisions of this 
 69.32  section. 
 69.33     Sec. 4.  [216B.098] [CUSTOMER PROTECTIONS.] 
 69.34     Subdivision 1.  [APPLICABILITY.] This section applies to 
 69.35  residential customers of public utilities, municipal utilities, 
 69.36  and cooperative electric associations. 
 70.1      Subd. 2.  [BUDGET BILLING PLANS.] A utility shall offer a 
 70.2   customer a budget billing plan for payment of charges for 
 70.3   service, including adequate notice to customers prior to 
 70.4   changing budget payment amounts.  Municipal utilities having 
 70.5   3,000 or fewer customers are exempt from this requirement.  
 70.6   Municipal utilities having more than 3,000 customers shall 
 70.7   implement this requirement within two years of the effective 
 70.8   date of this chapter. 
 70.9      Subd. 3.  [PAYMENT AGREEMENTS.] A utility shall offer a 
 70.10  payment agreement for the payment of arrears. 
 70.11     Subd. 4.  [UNDERCHARGES.] A utility shall offer a payment 
 70.12  agreement to customers who have been undercharged if no culpable 
 70.13  conduct by the customer or resident of the customer's household 
 70.14  caused the undercharge.  The agreement must cover a period equal 
 70.15  to the time over which the undercharge occurred.  No interest or 
 70.16  delinquency fee may be charged under this agreement. 
 70.17     Subd. 5.  [MEDICALLY NECESSARY EQUIPMENT.] A utility shall 
 70.18  reconnect or continue service to a customer's residence where a 
 70.19  medical emergency exists or where medical equipment requiring 
 70.20  electricity is necessary to sustain life is in use, provided 
 70.21  that the utility receives from a medical doctor written 
 70.22  certification, or initial certification by telephone and written 
 70.23  certification within five business days, that failure to 
 70.24  reconnect or continue service will impair or threaten the health 
 70.25  or safety of a resident of the customer's household.  The 
 70.26  customer must enter into a payment agreement. 
 70.27     Subd. 6.  [COMMISSION AUTHORITY.] The commission, or staff 
 70.28  designated by the commission, has the authority to order 
 70.29  resolutions of disputes involving alleged violations of this 
 70.30  chapter by a public utility or any other disputes involving 
 70.31  public utilities coming within its jurisdiction. 
 70.32     Sec. 5.  Minnesota Statutes 2000, section 216B.16, 
 70.33  subdivision 15, is amended to read: 
 70.34     Subd. 15.  [LOW-INCOME RATE PROGRAMS; REPORT.] (a) The 
 70.35  commission may consider ability to pay as a factor in setting 
 70.36  utility rates and may establish programs for low-income 
 71.1   residential ratepayers in order to ensure affordable, reliable, 
 71.2   and continuous service to low-income utility customers.  The 
 71.3   commission shall order a pilot program for at least one 
 71.4   utility.  In ordering pilot programs, the commission shall 
 71.5   consider the following: 
 71.6      (1) the potential for low-income programs to provide 
 71.7   savings to the utility for all collection costs including but 
 71.8   not limited to:  costs of disconnecting and reconnecting 
 71.9   residential ratepayers' service, all activities related to the 
 71.10  utilities' attempt to collect past due bills, utility working 
 71.11  capital costs, and any other administrative costs related to 
 71.12  inability to pay programs and initiatives; 
 71.13     (2) the potential for leveraging federal low-income energy 
 71.14  dollars to the state; and 
 71.15     (3) the impact of energy costs as a percentage of the total 
 71.16  income of a low-income residential customer. 
 71.17     (b) In determining the structure of the pilot utility 
 71.18  program, the commission shall: 
 71.19     (1) consult with advocates for and representatives of 
 71.20  low-income utility customers, administrators of energy 
 71.21  assistance and conservation programs, and utility 
 71.22  representatives; 
 71.23     (2) coordinate eligibility for the program with the state 
 71.24  and federal energy assistance program and low-income residential 
 71.25  energy programs, including weatherization programs; and 
 71.26     (3) evaluate comprehensive low-income programs offered by 
 71.27  utilities in other states. 
 71.28     (c) The commission shall implement at least one pilot 
 71.29  project by January 1, 1995, and shall allow a utility required 
 71.30  to implement a pilot project to recover the net costs of the 
 71.31  project in the utility's rates. 
 71.32     (d) The commission, in conjunction with the commissioner of 
 71.33  the department of public service and the commissioner of 
 71.34  economic security, shall review low-income rate programs and 
 71.35  shall report to the legislature by January 1, 1998.  The report 
 71.36  must include: 
 72.1      (1) the increase in federal energy assistance money 
 72.2   leveraged by the state as a result of this program; 
 72.3      (2) the effect of the program on low-income customer's 
 72.4   ability to pay energy costs; 
 72.5      (3) the effect of the program on utility customer bad debt 
 72.6   and arrearages; 
 72.7      (4) the effect of the program on the costs and numbers of 
 72.8   utility disconnections and reconnections and other costs 
 72.9   incurred by the utility in association with inability to pay 
 72.10  programs; 
 72.11     (5) the ability of the utility to recover the costs of the 
 72.12  low-income program without a general rate change; 
 72.13     (6) how other ratepayers have been affected by this 
 72.14  program; 
 72.15     (7) recommendations for continuing, eliminating, or 
 72.16  expanding the low-income pilot program; and 
 72.17     (8) how general revenue funds may be utilized in 
 72.18  conjunction with low-income programs. 
 72.19     (b) The purpose of the low-income programs is to lower the 
 72.20  percentage of income that low-income households devote to energy 
 72.21  bills, to increase customer payments, and to lower utility costs 
 72.22  associated with customer account collection activities.  In 
 72.23  ordering low-income programs, the commission may require 
 72.24  utilities to file program evaluations, including the effect of 
 72.25  the program on participant household energy burdens, the 
 72.26  coordination of other available low-income bill payment and 
 72.27  conservation resources, the effect of the program on service 
 72.28  disconnections, and the effect of the program on customer 
 72.29  payment behavior, utility collection costs, arrearages, and bad 
 72.30  debt. 
 72.31     Sec. 6.  [216B.79] [PREVENTATIVE MAINTENANCE.] 
 72.32     (a) The commission has the authority to ensure that public 
 72.33  utilities are making adequate infrastructure investments and 
 72.34  undertaking sufficient preventative maintenance with regard to 
 72.35  generation, transmission, and distribution facilities.  
 72.36     (b) The commission may make appropriate adjustments in a 
 73.1   utility's rates through an automatic adjustment of charges under 
 73.2   section 216B.16, accelerated depreciation of capital costs, or 
 73.3   other appropriate mechanisms, or make a recommendation to the 
 73.4   Federal Energy Regulatory Commission to make an appropriate 
 73.5   adjustment in a utility's allowed rate of return on those 
 73.6   utilities' transmission facilities, to provide incentive and 
 73.7   offset the costs of new energy infrastructure facility 
 73.8   construction. 
 73.9      Sec. 7.  Minnesota Statutes 2000, section 216C.41, 
 73.10  subdivision 5, is amended to read: 
 73.11     Subd. 5.  [AMOUNT OF PAYMENT.] (a) An incentive payment is 
 73.12  based on the number of kilowatt hours of electricity generated. 
 73.13  The amount of the payment is 1.5 cents per kilowatt hour.  For 
 73.14  electricity generated by qualified wind energy conversion 
 73.15  facilities, the incentive payment under this section is limited 
 73.16  to no more than 100 megawatts of nameplate capacity.  During any 
 73.17  period in which qualifying claims for incentive payments exceed 
 73.18  100 megawatts of nameplate capacity, the payments must be made 
 73.19  to producers in the order in which the production capacity was 
 73.20  brought into production.  
 73.21     (b) Beginning January 1, 2002, the total size of a wind 
 73.22  energy conversion system under this section must be determined 
 73.23  according to this paragraph.  Unless the systems are 
 73.24  interconnected with different distribution systems, the 
 73.25  nameplate capacity of one wind energy conversion system must be 
 73.26  combined with the nameplate capacity of any other wind energy 
 73.27  conversion system that is: 
 73.28     (1) located within five miles of the wind energy conversion 
 73.29  system; 
 73.30     (2) constructed within the same calendar year as the wind 
 73.31  energy conversion system; and 
 73.32     (3) under common ownership. 
 73.33  In the case of a dispute, the commissioner of commerce shall 
 73.34  determine the total size of the system, and shall draw all 
 73.35  reasonable inferences in favor of combining the systems. 
 73.36     (c) In making a determination under paragraph (b), the 
 74.1   commissioner of commerce may determine that two wind energy 
 74.2   conversion systems are under common ownership when the 
 74.3   underlying ownership structure contains similar persons or 
 74.4   entities, even if the ownership shares differ between the two 
 74.5   systems.  Wind energy conversion systems are not under common 
 74.6   ownership solely because the same person or entity provided 
 74.7   equity financing for the systems. 
 74.8      Sec. 8.  Minnesota Statutes 2000, section 216C.41, is 
 74.9   amended by adding a subdivision to read: 
 74.10     Subd. 6.  [OWNERSHIP; FINANCING; CURE.] (a) For the 
 74.11  purposes of subdivision 1, paragraph (c), clause (2), a wind 
 74.12  energy conversion facility qualifies if it is owned at least 51 
 74.13  percent by one or more of any combination of the entities listed 
 74.14  in that clause. 
 74.15     (b) A subsequent owner of a qualified facility may continue 
 74.16  to receive the incentive payment for the duration of the 
 74.17  original payment period if the subsequent owner qualifies for 
 74.18  the incentive under subdivision 1. 
 74.19     (c) Nothing in this section may be construed to deny 
 74.20  incentive payment to an otherwise qualified facility that has 
 74.21  obtained debt or equity financing for construction or operation 
 74.22  as long as the ownership requirements of subdivision 1 and this 
 74.23  subdivision are met.  If, during the incentive payment period 
 74.24  for a qualified facility, the owner of the facility is in 
 74.25  default of a lending agreement and the lender takes possession 
 74.26  of and operates the facility and makes reasonable efforts to 
 74.27  transfer ownership of the facility to an entity other than the 
 74.28  lender, the lender may continue to receive the incentive payment 
 74.29  for electricity generated and sold by the facility for a period 
 74.30  not to exceed 18 months.  A lender who takes possession of a 
 74.31  facility shall notify the commissioner immediately on taking 
 74.32  possession and, at least quarterly, document efforts to transfer 
 74.33  ownership of the facility. 
 74.34     (d) If, during the incentive payment period, a qualified 
 74.35  facility loses the right to receive the incentive because of 
 74.36  changes in ownership, the facility may regain the right to 
 75.1   receive the incentive upon cure of the ownership structure that 
 75.2   resulted in the loss of eligibility and may reapply for the 
 75.3   incentive, but in no case may the payment period be extended 
 75.4   beyond the original ten-year limit. 
 75.5      (e) A subsequent or requalifying owner under paragraph (b)  
 75.6   or (d) retains the facility's original priority order for 
 75.7   incentive payments as long as the ownership structure 
 75.8   requalifies within two years from the date the facility became 
 75.9   unqualified or two years from the date a lender takes possession.
 75.10     Sec. 9.  [REPEALER.] 
 75.11     Minnesota Statutes 2000, sections 216B.241 and 216C.18 are 
 75.12  repealed. 
 75.13     Sec. 10.  [EFFECTIVE DATE.] 
 75.14     This article is effective the day following final enactment.
 75.15                             ARTICLE 7
 75.16                    SAFETY AND SERVICE STANDARDS
 75.17     Section 1.  [216B.81] [DEFINITIONS.] 
 75.18     Subdivision 1.  [SCOPE.] The terms used in this article 
 75.19  have the meanings given them in this section. 
 75.20     Subd. 2.  [AVERAGE NUMBER OF CUSTOMERS SERVED.] "Average 
 75.21  number of customers served" means the number of active, metered, 
 75.22  customer accounts available in a utility's 
 75.23  interruption-reporting database on the day that an interruption 
 75.24  occurs. 
 75.25     Subd. 3.  [CIRCUIT.] "Circuit" means a set of conductors 
 75.26  serving customer loads that are capable of being separated from 
 75.27  the serving substation automatically by a recloser, fuse, 
 75.28  sectionalizing equipment, and other devices. 
 75.29     Subd. 4.  [COMPONENT.] "Component" means a piece of 
 75.30  equipment, a line, a section of line, or a group of items that 
 75.31  is an entity for purposes of reporting, analyzing, and 
 75.32  predicting interruptions. 
 75.33     Subd. 5.  [CUSTOMER.] "Customer" means a contiguous 
 75.34  electrical service location, regardless of the number of meters 
 75.35  at the location. 
 75.36     Subd. 6.  [CUSTOMER INTERRUPTION.] "Customer interruption" 
 76.1   means the loss of service due to a forced outage for more than 
 76.2   five minutes, for one or more customers, which is the result of 
 76.3   one or more component failures. 
 76.4      Subd. 7.  [CUSTOMERS' INTERRUPTIONS CAUSED BY POWER 
 76.5   RESTORATION PROCESS.] "Customers' interruptions caused by power 
 76.6   restoration process" means when customers lose power as a result 
 76.7   of the process of restoring power.  The duration of these 
 76.8   outages is included in the customer-minutes of interruption.  
 76.9   Only the customers affected by the power restoration outages 
 76.10  that were not affected by the original outage are added to the 
 76.11  number of customer interruptions.  
 76.12     Subd. 8.  [CUSTOMER-MINUTES OF 
 76.13  INTERRUPTION.] "Customer-minutes of interruption" means the 
 76.14  number of minutes of forced outage duration multiplied by the 
 76.15  number of customers affected. 
 76.16     Subd. 9.  [ELECTRIC DISTRIBUTION LINE.] "Electric 
 76.17  distribution line" means circuits operating at less than 40,000 
 76.18  volts. 
 76.19     Subd. 10.  [FORCED OUTAGE.] "Forced outage" means an outage 
 76.20  that cannot be deferred. 
 76.21     Subd. 11.  [MAJOR CATASTROPHIC EVENTS.] "Major catastrophic 
 76.22  events" means events that are beyond the utility's control that 
 76.23  result in widespread system damages causing customer 
 76.24  interruptions that affect at least ten percent of the customers 
 76.25  in the system or in an operating area or that result in 
 76.26  customers being without electric service for durations of at 
 76.27  least 24 hours. 
 76.28     Subd. 12.  [MAJOR STORM.] "Major storm" means a period of 
 76.29  severe adverse weather resulting in widespread system damage 
 76.30  causing customer interruptions that affect at least ten percent 
 76.31  of the customers on the system or in an operating area or that 
 76.32  result in customers being without electric service for durations 
 76.33  of at least 24 hours. 
 76.34     Subd. 13.  [MOMENTARY INTERRUPTION.] "Momentary 
 76.35  interruption" means an interruption of electric service with a 
 76.36  duration shorter than the time necessary to be classified as a 
 77.1   customer interruption. 
 77.2      Subd. 14.  [OPERATING AREA.] "Operating area" means a 
 77.3   geographical subdivision of each electric utility's service 
 77.4   territory that functions under the direction of a company office 
 77.5   and may be used for reporting interruptions under this article.  
 77.6   These areas may also be referred to as regions, divisions, or 
 77.7   districts. 
 77.8      Subd. 15.  [OUTAGE.] "Outage" means the failure of a power 
 77.9   system component that results in one or more customer 
 77.10  interruptions. 
 77.11     Subd. 16.  [OUTAGE DURATION.] "Outage duration" means the 
 77.12  one minute or greater period from the initiation of an 
 77.13  interruption to a customer until service has been restored to 
 77.14  that customer. 
 77.15     Subd. 17.  [PARTIAL CIRCUIT OUTAGE CUSTOMER 
 77.16  COUNT.] "Partial circuit outage customer count" means when only 
 77.17  part of a circuit experiences an outage, the number of customers 
 77.18  affected is estimated, unless an actual count is available.  
 77.19  When power is partially restored, the number of customers 
 77.20  restored is also estimated.  Most utilities use estimates based 
 77.21  on the portion of the circuit restored. 
 77.22     Subd. 18.  [PLANNED OUTAGES.] "Planned outages" means those 
 77.23  outages scheduled by the utility.  These interruptions are 
 77.24  sometimes necessary to connect new customers or perform 
 77.25  maintenance activities safely.  They must not be included in the 
 77.26  calculation of reliability indexes. 
 77.27     Subd. 19.  [RELIABILITY.] "Reliability" means the degree to 
 77.28  which electric service is supplied without interruption. 
 77.29     Subd. 20.  [RELIABILITY INDEXES.] "Reliability indexes" 
 77.30  include the following performance indices for measuring 
 77.31  frequency and duration of service interruptions: 
 77.32     (a) The system average interruption frequency index is the 
 77.33  average number of interruptions per customer per year.  It is 
 77.34  determined by dividing the total annual number of customer 
 77.35  interruptions by the average number of customers served during 
 77.36  the year. 
 78.1      (b) The system average interruption duration index is the 
 78.2   average customer-minutes of interruption per customer.  It is 
 78.3   determined by dividing the annual sum of customer-minutes of 
 78.4   interruption by the average number of customers served during 
 78.5   the year. 
 78.6      (c) The customer average interruption duration index is the 
 78.7   average customer-minutes of interruption per customer 
 78.8   interruption.  It approximates the average length of time 
 78.9   required to complete service restoration.  It is determined by 
 78.10  dividing the annual sum of all customer-minutes of interruption 
 78.11  durations by the annual number of customer interruptions. 
 78.12     Sec. 2.  [216B.82] [RECORDING SERVICE INTERRUPTION 
 78.13  INDEXES.] 
 78.14     Subdivision 1.  [SYSTEM INTERRUPTION DATA.] Each electric 
 78.15  utility with 10,000 retail customers or more shall keep a record 
 78.16  of the necessary interruption data and calculate the system 
 78.17  average interruption frequency index, system average 
 78.18  interruption duration index, and customer average interruption 
 78.19  duration index of its system, and of each operating area, if 
 78.20  applicable, at the end of each calendar year for the previous 
 78.21  12-month period. 
 78.22     Subd. 2.  [CIRCUIT INTERRUPTION DATA.] Unless a utility 
 78.23  uses alternative criteria as provided in section 216B.83, 
 78.24  subdivision 2, paragraph (d), each utility also shall, at the 
 78.25  end of each calendar year, calculate the system average 
 78.26  interruption frequency index, system average interruption 
 78.27  duration index, and customer average interruption duration index 
 78.28  for each circuit in each operating area.  Each circuit in each 
 78.29  operating area must then be listed in order separately according 
 78.30  to its system average interruption frequency index, its system 
 78.31  average interruption duration index, and its customer average 
 78.32  interruption duration index, beginning with the highest values 
 78.33  for each index. 
 78.34     Sec. 3.  [216B.83] [ANNUAL REPORT.] 
 78.35     Subdivision 1.  [SUMMARY REPORT GENERALLY.] Beginning on 
 78.36  July 1, 2002, and by July 1 of every year thereafter, each 
 79.1   electric utility with 10,000 retail customers or more shall file 
 79.2   with the commission, or in the case of a cooperative electric 
 79.3   association or municipal utility, with the local governing body 
 79.4   of the utility or association a report summarizing various 
 79.5   measures of reliability.  The form of the report is subject to 
 79.6   review and comment by the commission staff.  Names and numbers 
 79.7   used to identify operating areas or individual circuits may 
 79.8   conform to the utility's practice, but should allow ready 
 79.9   identification of the geographic location or the general area 
 79.10  served.  Electronic recording and reporting of the required data 
 79.11  and information is encouraged.  
 79.12     Subd. 2.  [INFORMATION REQUIRED.] (a) The report must 
 79.13  include at least the information described in paragraphs (b) to 
 79.14  (h). 
 79.15     (b) The report must provide an overall assessment of the 
 79.16  reliability of performance including the aggregate system 
 79.17  average interruption frequency index, system average 
 79.18  interruption duration index, and customer average interruption 
 79.19  duration index by system and each operating area, as applicable. 
 79.20     (c) The report must include a list of the worst performing 
 79.21  circuits based on system average interruption frequency index, 
 79.22  system average interruption duration index, and customer average 
 79.23  interruption duration index for the calendar year.  This portion 
 79.24  of the report must describe the actions that the utility has 
 79.25  taken or will take to remedy the conditions responsible for each 
 79.26  listed circuit's unacceptable performance.  The actions taken or 
 79.27  planned should be briefly described.  Target dates for 
 79.28  corrective actions must be included in the report.  When the 
 79.29  utility determines that actions on its part are unwarranted, its 
 79.30  report shall provide adequate justification for that conclusion. 
 79.31     (d) Utilities that use or prefer alternative criteria for 
 79.32  measuring individual circuit performance to those described in 
 79.33  paragraphs (b) and (c) and that are required by this section to 
 79.34  submit an annual report of reliability data, shall submit their 
 79.35  alternative listing of circuits along with the criteria used to 
 79.36  rank circuit performance. 
 80.1      (e) Information must be included with respect to any report 
 80.2   on the accomplishment of the improvements proposed in prior 
 80.3   reports for which completion has not been previously reported. 
 80.4      (f) The report must describe any new reliability or power 
 80.5   quality programs and changes that are made to existing programs. 
 80.6      (g) It must include a status report of any long-range 
 80.7   electric distribution plans. 
 80.8      (h) In addition to the information included in paragraph 
 80.9   (b), each utility that has the technical capability and 
 80.10  administrative resources shall report the following additional 
 80.11  service quality information: 
 80.12     (1) route miles of electric distribution line reconstructed 
 80.13  during the year, with separate totals for single- and 
 80.14  three-phase circuits provided; 
 80.15     (2) total route miles of electric distribution line in 
 80.16  service at year's end, segregated by voltage level; 
 80.17     (3) monthly average speed of answer for telephone calls 
 80.18  received regarding emergencies; 
 80.19     (4) the average number of calendar days a utility takes to 
 80.20  install and energize service to a customer site once it is ready 
 80.21  to receive service, with a separate average calculated for each 
 80.22  month, including all extensions energized during the calendar 
 80.23  month; 
 80.24     (5) the total number of written and telephone customer 
 80.25  complaints received in the areas of safety, outages, power 
 80.26  quality, customer property damage, and other areas, by month 
 80.27  filed; 
 80.28     (6) total annual tree-trimming budget and actual expenses; 
 80.29  and 
 80.30     (7) total annual projected and actual miles of tree-trimmed 
 80.31  distribution line. 
 80.32     Sec. 4.  [216B.84] [INITIAL HISTORICAL RELIABILITY 
 80.33  PERFORMANCE REPORT.] 
 80.34     (a) Each electric utility with 10,000 retail customers or 
 80.35  more that has historically used measures of system, operating 
 80.36  area, and circuit reliability performance shall initially submit 
 81.1   annual system average interruption frequency index, system 
 81.2   average interruption duration index, and customer average 
 81.3   interruption duration index data for the previous three years.  
 81.4   Those utilities that have this data for some time period less 
 81.5   than three years shall submit data for those years it is 
 81.6   available. 
 81.7      (b) Those utilities whose historical reliability 
 81.8   performance data is similar or related to those measures listed 
 81.9   in paragraph (a), but differs due to how the parameters are 
 81.10  defined or calculated, shall submit the data it has and explain 
 81.11  any material differences from the prescribed indices.  After the 
 81.12  effective date of this section, utilities shall modify their 
 81.13  reliability performance measures to conform to those specified 
 81.14  in sections 216B.81 to 216B.87 for purposes of consistent 
 81.15  reporting of comparable data in the future. 
 81.16     Sec. 5.  [216B.85] [INTERRUPTIONS OF SERVICE; RECORDS; 
 81.17  NOTICE.] 
 81.18     Subdivision 1.  [RECORDS.] (a) Each utility shall keep 
 81.19  records of all interruptions to service affecting the entire 
 81.20  distribution system of any single community or an important 
 81.21  division of a community, and include in the records each 
 81.22  interruption's location, date and time, and duration; the 
 81.23  approximate number of customers affected; the circuit or 
 81.24  circuits involved; and, when known, the cause of each 
 81.25  interruption. 
 81.26     (b) When complete distribution systems or portions of 
 81.27  communities have service furnished from unattended stations, 
 81.28  these records must be kept to the extent practicable.  The 
 81.29  record of unattended stations shall show interruptions that 
 81.30  require attention to restore service, with the estimated time of 
 81.31  interruption.  Breaker or fuse operations affecting service 
 81.32  should also be indicated even though duration of interruption 
 81.33  may not be known. 
 81.34     Subd. 2.  [NOTICE OF INTERRUPTIONS OF BULK POWER SUPPLY 
 81.35  FACILITIES.] (a) Each utility owning or operating bulk power 
 81.36  supply facilities shall record any event described in clauses 
 82.1   (1) to (5) involving any generating unit or electric facilities 
 82.2   operating at a nominal voltage of 69 kilovolts or higher, and 
 82.3   shall make such records available to the commission semiannually 
 82.4   or upon request of the commission: 
 82.5      (1) any interruption or loss of service to customers for 15 
 82.6   minutes or more to aggregate firm loads in excess of 200,000 
 82.7   kilowatts; 
 82.8      (2) any interruption or loss of service to customers for 15 
 82.9   minutes or more to aggregate firm loads exceeding the lesser of 
 82.10  100,000 kilowatts or one-half of the current annual system peak 
 82.11  load and not required to be recorded under clause (1); 
 82.12     (3) any decision to issue a public request for reduction in 
 82.13  use of electricity; 
 82.14     (4) an action to reduce firm customer loads by reduction of 
 82.15  voltage for reasons of maintaining adequacy of bulk electric 
 82.16  power supply; and 
 82.17     (5) any action to reduce firm customer loads by manual 
 82.18  switching, operation of automatic load-shedding devices, or any 
 82.19  other means for reasons of maintaining adequacy of bulk electric 
 82.20  power supply.  
 82.21     Subd. 3.  [NOTICE OF OTHER INTERRUPTIONS OF POWER.] Each 
 82.22  utility shall record service interruptions of 60 minutes or more 
 82.23  to an entire distribution substation bus or entire feeder 
 82.24  serving either 500 or more customers or entire cities or 
 82.25  villages having 200 or more customers.  
 82.26     Subd. 4.  [INFORMATION REQUIRED.] The written records 
 82.27  required in subdivisions 2 and 3 must include the date, time, 
 82.28  duration, general location, approximate number of customers 
 82.29  affected, identification of circuit or circuits involved, and, 
 82.30  when known, the cause of the interruption.  When extensive 
 82.31  interruptions occur, as from a storm, a narrative record 
 82.32  including the extent of the interruptions and system damage, 
 82.33  estimated number of customers affected, and a list of entire 
 82.34  communities interrupted may be recorded in lieu of records of 
 82.35  individual interruptions.  When customer service interruptions 
 82.36  are necessary, the utility shall make reasonable efforts to 
 83.1   notify affected customers in advance.  
 83.2      Sec. 6.  [216B.86] [CUSTOMERS' COMPLAINTS.] 
 83.3      Each utility shall keep a record of complaints received by 
 83.4   it from its customers in regard to safety or service, and the 
 83.5   operation of its system, with appropriate response times 
 83.6   designated for critical safety and monetary loss situations and 
 83.7   shall investigate if appropriate.  The record must show the name 
 83.8   and address of the complainant, the date and nature of the 
 83.9   complaint, the priority assigned to the assistance, and its 
 83.10  disposition and the time and date of its disposition. 
 83.11     Sec. 7.  [216B.87] [STANDARDS FOR DISTRIBUTION UTILITIES.] 
 83.12     (a) The commission and each cooperative electric 
 83.13  association and municipal utility shall, only as resources 
 83.14  allow, adopt standards for safety, reliability, and service 
 83.15  quality for distribution utilities.  Standards for cooperative 
 83.16  electric associations and municipal utilities should be as 
 83.17  consistent as possible with the commission standards. 
 83.18     (b) Reliability standards must be based on the system 
 83.19  average interruption frequency index, system average 
 83.20  interruption duration index, and customer average interruption 
 83.21  duration index measurement indices.  Service quality standards 
 83.22  must specify, if technically and administratively feasible: 
 83.23     (1) average call center response time; 
 83.24     (2) customer disconnection rate; 
 83.25     (3) meter-reading frequency; 
 83.26     (4) complaint resolution response time; and 
 83.27     (5) service extension request response time. 
 83.28     (c) Minimum performance standards developed under this 
 83.29  section must treat similarly situated distribution systems 
 83.30  similarly and recognize differing characteristics of system 
 83.31  design and hardware. 
 83.32     (d) Electric distribution utilities shall comply with all 
 83.33  applicable governmental and industry standards required for the 
 83.34  safety, design, construction, and operation of electric 
 83.35  distribution facilities, including section 326.243. 
 83.36     Sec. 8.  [COST BENEFIT ANALYSIS.] 
 84.1      The commissioner of commerce shall provide an analysis of 
 84.2   the costs and benefits to consumers and utilities of the 
 84.3   provisions of sections 1 to 7, including any recommended changes 
 84.4   to those provisions, to the chairs of the house of 
 84.5   representatives and senate policy and finance committees with 
 84.6   jurisdiction over electric utility issues by February 1, 2002. 
 84.7      Sec. 9.  [EFFECTIVE DATE.] 
 84.8      Sections 1 to 7 are effective July 1, 2003.  Section 8 is 
 84.9   effective the day following final enactment.