1.1                          A bill for an act 
  1.2             relating to energy; enacting the Minnesota Energy 
  1.3             Security and Reliability Act; requiring an energy 
  1.4             security blueprint and a state reliability plan; 
  1.5             providing for essential energy infrastructure; 
  1.6             eliminating the requirement for individual utility 
  1.7             plans; creating an independent reliability 
  1.8             administrator; modifying provisions for siting, 
  1.9             routing, and determining the need for large electric 
  1.10            power facilities; regulating conservation expenditures 
  1.11            by energy utilities and eliminating state pre-approval 
  1.12            of conservation plans by public utilities; encouraging 
  1.13            regulatory flexibility in supplying and obtaining 
  1.14            energy; regulating interconnection of distributed 
  1.15            utility resources; providing for safety and service 
  1.16            standards from distribution utilities; clarifying the 
  1.17            state cold weather disconnection requirements; making 
  1.18            technical, conforming, and clarifying changes; 
  1.19            amending Minnesota Statutes 2000, sections 116.07, 
  1.20            subdivision 4a; 116C.52, subdivision 4; 116C.53, 
  1.21            subdivision 3; 116C.57, subdivisions 1, 2, 4, by 
  1.22            adding subdivisions; 116C.58; 116C.59, subdivision 1; 
  1.23            116C.60; 116C.61, subdivision 1; 116C.62; 116C.64; 
  1.24            116C.645; 116C.65; 116C.66; 116C.69; 216A.03, 
  1.25            subdivision 3a; 216B.03; 216B.095; 216B.097, 
  1.26            subdivision 1; 216B.16, subdivisions 1, 6b, 6c, 7, by 
  1.27            adding a subdivision; 216B.162, subdivision 8; 
  1.28            216B.1621, subdivision 2; 216B.164, subdivision 4; 
  1.29            216B.241, subdivisions 1, 1a, 1b, 2, 2a, by adding 
  1.30            subdivisions; 216B.2421, subdivision 2, by adding a 
  1.31            subdivision; 216B.2423, subdivision 2; 216B.243, 
  1.32            subdivisions 2, 3, 4, by adding a subdivision; 
  1.33            216B.42, subdivision 1; 216C.17, subdivision 3; 
  1.34            216C.41; proposing coding for new law in Minnesota 
  1.35            Statutes, chapters 116C; 216B; repealing Minnesota 
  1.36            Statutes 2000, sections 116C.55; 116C.57, subdivisions 
  1.37            3, 5, 5a; 116C.67; 216B.241, subdivision 1c; 
  1.38            216B.2422, subdivisions 2, 6; 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.011] [ADMINISTRATOR; ASSESSMENTS; 
  2.4   APPROPRIATION; REPORT.] 
  2.5      Subdivision 1.  [CREATION.] (a) Recognizing the critical 
  2.6   importance of adequate, reliable, and environmentally sound 
  2.7   energy services to the state's economy and the well-being of its 
  2.8   citizens, and that responsibility for reliability is dispersed 
  2.9   among several state agencies, the commissioner of commerce shall 
  2.10  create an independent reliability administrator within the 
  2.11  department of commerce.  
  2.12     (b) The commissioner, with the advice and consent of the 
  2.13  commission, shall appoint the administrator for a term 
  2.14  concurrent with that of the governor.  The administrator may be 
  2.15  removed only for cause.  In addition to jointly appointing the 
  2.16  administrator, the commissioner, the commission chair, and the 
  2.17  director of the office of strategic and long-range planning 
  2.18  shall oversee and direct the work of the administrator, annually 
  2.19  audit the expenses of the administrator, and biennially approve 
  2.20  the budget of the administrator. 
  2.21     (c) The administrator may utilize staff from the 
  2.22  department, commission, and the board, at the discretion of the 
  2.23  administrative heads of those agencies; may hire staff; and may 
  2.24  contract for technical expertise in performing duties when 
  2.25  existing state resources are required for other state 
  2.26  responsibilities or when special expertise is required. 
  2.27     (d) The salary of the administrator is governed by section 
  2.28  15A.0815, subdivision 2. 
  2.29     Subd. 2.  [DUTIES.] (a) The administrator shall increase 
  2.30  state agency technical expertise and understanding of 
  2.31  reliability needs and increase public confidence in proposed 
  2.32  infrastructure projects by: 
  2.33     (1) modeling and monitoring the use and operation of the 
  2.34  energy infrastructure in the state, including generation 
  2.35  facilities, transmission lines, natural gas pipelines, and other 
  2.36  energy infrastructure; 
  3.1      (2) identifying weaknesses, constraints, and conditions 
  3.2   that materially limit the adequacy of energy supply, efficiency 
  3.3   of energy service, or reliability of energy service to consumers 
  3.4   in Minnesota that may require construction of a generation, 
  3.5   transmission, or natural gas pipeline project; 
  3.6      (3) developing and consolidating technical analyses of 
  3.7   proposed infrastructure projects, to be utilized by the 
  3.8   commission, the department, the office of attorney general, the 
  3.9   environmental quality board, and the pollution control agency in 
  3.10  reviewing applications for infrastructure approvals under the 
  3.11  jurisdiction of those respective agencies; 
  3.12     (4) assessing, from a technical standpoint, assertions of 
  3.13  need for additional infrastructure for the members of the 
  3.14  regional energy infrastructure planning groups; 
  3.15     (5) developing, issuing, and presenting the reliability 
  3.16  status report required under subdivision 4 and the state 
  3.17  reliability plan under section 216B.012; 
  3.18     (6) hosting public meetings around the state to present 
  3.19  independent, factual, expert, technical information on 
  3.20  infrastructure proposals; and 
  3.21     (7) coordinating with regional energy infrastructure 
  3.22  planning groups; regulators and reliability officials of other 
  3.23  states; regional reliability entities; and the federal 
  3.24  government. 
  3.25     (b) The commission, department, and environmental quality 
  3.26  board shall refer applications for transmission infrastructure 
  3.27  approvals to the administrator for initial technical analysis of 
  3.28  the proposed infrastructure improvement on reliability of energy 
  3.29  services to Minnesota consumers.  The administrator shall 
  3.30  provide written and oral technical assistance on the application 
  3.31  to each referring agency, and shall provide such advice and 
  3.32  analysis as that agency deems necessary. 
  3.33     (c) The administrator shall certify its administrative 
  3.34  costs to the commission on a monthly basis, and shall specify 
  3.35  those costs that are general in nature, and those that were 
  3.36  incurred on a specific application or with regard to a specific 
  4.1   utility.  The commission shall review those costs, and shall 
  4.2   order payment within 30 days of commission review.  The 
  4.3   department shall render a bill to the utility or utilities, 
  4.4   either at the conclusion of the proceeding, analysis, or 
  4.5   service, or from time to time during the course of the 
  4.6   proceeding, analysis, or service.  The bill constitutes notice 
  4.7   of the assessment and a demand for payment.  The amount of the 
  4.8   bills so rendered by the department must be paid by the public 
  4.9   utility into the state treasury within 30 days from the date of 
  4.10  billing and are appropriated to the administrator for the 
  4.11  purposes provided in this section.  General administrative costs 
  4.12  of the administrator must not exceed $2,000,000 for a fiscal 
  4.13  biennium; however, additional amounts may be incurred and 
  4.14  recovered above this amount, if the commissioner and chair of 
  4.15  the commission deem the additional amounts to be necessary.  The 
  4.16  administrator shall provide a detailed accounting of its 
  4.17  finances to the commissioner and to the chairs of the house and 
  4.18  senate finance committees with jurisdiction over the 
  4.19  department's budget.  Costs that are of a general nature must be 
  4.20  apportioned among all energy utilities in proportion to their 
  4.21  respective gross operating revenues from retail sales of gas or 
  4.22  electric service within the state during the last calendar 
  4.23  year.  Within 30 days after the date of the mailing of any bill 
  4.24  as provided by this subdivision and subdivision 3, the utility 
  4.25  against which the bill has been rendered may file with the 
  4.26  commission objections setting out the grounds upon which it is 
  4.27  claimed the bill is excessive, erroneous, unlawful, or invalid.  
  4.28  Within 60 days, the commission shall hold a hearing and issue an 
  4.29  order in accordance with its findings.  The order is appealable 
  4.30  in the same manner as other final orders of the commission.  The 
  4.31  commission shall approve or approve as modified a rate schedule 
  4.32  providing for the automatic adjustment of charges to recover 
  4.33  amounts paid by utilities under this section. 
  4.34     Subd. 3.  [TECHNICAL ASSISTANCE.] Upon request, the 
  4.35  administrator shall provide technical assistance regarding 
  4.36  matters unrelated to applications for infrastructure 
  5.1   improvements to the department, the commission, and the board.  
  5.2      Subd. 4.  [RELIABILITY STATUS REPORT.] (a) The commission 
  5.3   shall require all distribution utilities, as technically and 
  5.4   administratively feasible, to report to the administrator on 
  5.5   operating and planning reserves, available transmission 
  5.6   capacity, outages of major generation units and feeders of 
  5.7   distribution and transmissions facilities, the adequacy of stock 
  5.8   and equipment, and any other information necessary to assess the 
  5.9   current and future reliability of energy service in this state.  
  5.10  Distribution utilities that are currently required to file 
  5.11  resource plans may submit updates, if applicable. 
  5.12     (b) The administrator shall, by January 1 of each 
  5.13  odd-numbered year beginning in 2003, assess and report to the 
  5.14  commissioner, with copies to the commission and the chairs of 
  5.15  the house and senate committees with jurisdiction over energy 
  5.16  policy issues, the status of the reliability of electric service 
  5.17  in the state and make recommendations, if applicable, for 
  5.18  regulatory or legislative action. 
  5.19     Sec. 3.  [216B.012] [STATE RELIABILITY PLAN.] 
  5.20     (a) By January 1 of every odd-numbered year, the 
  5.21  administrator shall develop and present to the commissioner 
  5.22  recommendations for a draft state reliability plan, consisting 
  5.23  of critical transmission system upgrades and new transmission 
  5.24  projects of 100 kilovolts or greater.  Only projects that, in 
  5.25  the opinion of the administrator, meet the criteria established 
  5.26  in section 216B.243 for issuing certificates of need and public 
  5.27  purpose designations for large energy facilities may be 
  5.28  recommended to be included in the draft administrator's 
  5.29  recommendations.  The plan may describe projects generally.  
  5.30  Specific locations and routes must be determined by the 
  5.31  environmental quality board as provided in section 116C.57 or 
  5.32  116C.575. 
  5.33     (b) In developing the administrator's recommendations, the 
  5.34  administrator shall consider: 
  5.35     (1) the most recent state energy security blueprint issued 
  5.36  under section 216B.015; 
  6.1      (2) the most recent regional energy infrastructure reports 
  6.2   issued by the regional energy infrastructure planning regions; 
  6.3      (3) any transmission plan issued by a federally approved 
  6.4   regional reliability entity for the region that includes 
  6.5   Minnesota, or issued by the reliability entity for this region 
  6.6   that is a member of the North American Electric Reliability 
  6.7   Council, or any successor organization; 
  6.8      (4) any deficiencies noticed under section 216B.019, 
  6.9   subdivision 5; 
  6.10     (5) any transmission plan developed and proposed jointly by 
  6.11  the transmission-owning or transmission-operating entities in 
  6.12  the state; 
  6.13     (6) the needs of transmission-dependent utilities and 
  6.14  customers in Minnesota; and 
  6.15     (7) any other information the administrator deems necessary 
  6.16  or reasonable.  
  6.17     (c) Each energy utility, energy service supplier, or 
  6.18  transmission owner or operator shall comply with all requests 
  6.19  for information that the administrator deems necessary to 
  6.20  complete the proposed plan. 
  6.21     (d) Within 30 days of receiving the administrator's 
  6.22  recommendations, the commissioner shall propose a state 
  6.23  reliability plan to the commission.  The commission shall 
  6.24  approve, reject, or approve as modified the plan proposed by the 
  6.25  administrator within 180 days of issuance and shall publish the 
  6.26  plan in the State Register.  In making its decision under this 
  6.27  paragraph, the commission shall impose the criteria and 
  6.28  procedures established in section 216B.243 for issuing 
  6.29  certificates of need and public purpose designations.  Each 
  6.30  project in a state reliability plan approved by the commission 
  6.31  is exempt from additional commission review under section 
  6.32  216B.243. 
  6.33     (e) The administrator shall hold public meetings in all 
  6.34  areas of the state affected by the reliability plan.  
  6.35     (f) This chapter may not be construed to undermine the 
  6.36  existing and continuing obligation of the public utilities, 
  7.1   municipal utilities, and cooperative electric associations that 
  7.2   operate and provide service in this state to be ultimately 
  7.3   responsible for (1) providing reliable, affordable, safe, and 
  7.4   efficient energy services to their customers in this state, (2) 
  7.5   planning to meet the resource and infrastructure needs of those 
  7.6   customers, or (3) ensuring that those resources and 
  7.7   infrastructure are sited and constructed or otherwise acquired. 
  7.8      Sec. 4.  [216B.013] [EXISTING GENERATION FACILITIES.] 
  7.9      In order to continue the low-maintenance and low-cost 
  7.10  service that the existing base-load generation facilities in 
  7.11  Minnesota have provided to Minnesota consumers, and to provide 
  7.12  power to meet the growing demand for electricity by Minnesota 
  7.13  consumers and businesses, it is the policy of the state that 
  7.14  these facilities be maintained and upgraded consistent with 
  7.15  energy policy goals established pursuant to this chapter.  The 
  7.16  public utilities commission, department, and other state 
  7.17  agencies with regulatory jurisdiction over the operation of 
  7.18  these facilities shall take all steps necessary to incorporate 
  7.19  this state policy into the regulatory decisions made by each 
  7.20  respective agency. 
  7.21     Sec. 5.  [216B.014] [ENERGY SECURITY AND RELIABILITY.] 
  7.22     (a) It is a fundamental goal of Minnesota's energy and 
  7.23  utility policy that state policymakers maximize the state's 
  7.24  energy security.  
  7.25     (b) "Energy security" means, among other things, ensuring 
  7.26  that the state's energy sources are: 
  7.27     (1) diverse, including (i) traditional sources such as 
  7.28  coal, natural gas, waste-to-energy, and nuclear facilities, (ii) 
  7.29  renewable sources such as wind, biomass, and agricultural waste 
  7.30  generation, and (iii) high-efficiency, low-emissions distributed 
  7.31  generation sources such as fuel cells and microturbines; 
  7.32     (2) to the extent feasible, produced in the state; 
  7.33     (3) environmentally sustainable; 
  7.34     (4) available to consumers at affordable and stable rates 
  7.35  or prices; and 
  7.36     (5) above all, reliable.  "Reliable" means, among other 
  8.1   things, that adequate resources and infrastructure are in place, 
  8.2   and are planned for, to provide efficient, dependable, and 
  8.3   secure energy services to Minnesota consumers.  
  8.4      Sec. 6.  [216B.015] [ENERGY SECURITY BLUEPRINT.] 
  8.5      (a) The commissioner shall develop a draft energy security 
  8.6   blueprint by March 1, 2002, and every four years thereafter.  
  8.7   The blueprint must: 
  8.8      (1) identify important trends and issues in energy supply, 
  8.9   consumption, conservation, and costs; 
  8.10     (2) set energy goals; and 
  8.11     (3) develop strategies to meet the goals. 
  8.12     (b) For the purposes of sections 216B.012 to 216B.019, the 
  8.13  terms:  
  8.14     (1) "electric utility" means an entity that is a public 
  8.15  utility; a cooperative electric association providing 
  8.16  generation, transmission, or distribution services; a municipal 
  8.17  utility; or a municipal power agency; and 
  8.18     (2) "energy utility" means an electric utility, or an 
  8.19  entity providing natural gas to retail consumers. 
  8.20     Sec. 7.  [216B.016] [ENERGY BLUEPRINT CONTENTS.] 
  8.21     The energy blueprint must include: 
  8.22     (1) the amount and type of projected statewide energy 
  8.23  consumption over the next ten years; 
  8.24     (2) a determination of whether and the extent to which 
  8.25  existing and anticipated energy production and transportation 
  8.26  facilities will or will not be able to supply needed energy; 
  8.27     (3) a determination of the potential for conservation to 
  8.28  meet some or all of the projected need for energy; 
  8.29     (4) an assessment of the environmental impact of projected 
  8.30  energy consumption over the next ten years, prepared by the 
  8.31  commissioner of the pollution control agency in consultation 
  8.32  with other state agencies and other interested persons, with 
  8.33  strategies to mitigate those impacts; and 
  8.34     (5) benchmarks to measure and monitor supply adequacy and 
  8.35  infrastructure capacity, and to assess the overall reliability 
  8.36  of the state's electric system. 
  9.1      Sec. 8.  [216B.017] [ENERGY GOALS.] 
  9.2      (a) The blueprint must recommend statewide goals and list 
  9.3   strategies to accomplish the following goals for: 
  9.4      (1) energy conservation and recovery; 
  9.5      (2) limiting adverse environmental emissions from the 
  9.6   generation of electric energy consumed in the state; 
  9.7      (3) production of electric energy consumed in the state 
  9.8   from renewable energy sources; 
  9.9      (4) deployment of distributed electric generation 
  9.10  technologies; 
  9.11     (5) ensuring that energy service is affordable and 
  9.12  available to all consumers in the state; 
  9.13     (6) minimizing the imposition of social costs on energy 
  9.14  consumers through energy rates or prices; and 
  9.15     (7) increasing the efficiency of the regulatory 
  9.16  infrastructure and reducing regulatory and administrative costs. 
  9.17     (b) The goals adopted in the blueprint may be one-time 
  9.18  goals or a series of goals to meet overall objectives.  The 
  9.19  commissioner and the administrator shall jointly present these 
  9.20  goals, and any associated strategies that require changes to 
  9.21  state law, to the legislature for modification and approval.  
  9.22     Sec. 9.  [216B.018] [BLUEPRINT DEVELOPMENT.] 
  9.23     Subdivision 1.  [PUBLIC PARTICIPATION.] The commissioner 
  9.24  shall: 
  9.25     (1) invite public and stakeholder comment and participation 
  9.26  during blueprint development; and 
  9.27     (2) hold at least one public meeting on the proposed 
  9.28  blueprint in each energy infrastructure planning region of the 
  9.29  state after at least 30 days' public notice in the region. 
  9.30     Subd. 2.  [NOTICE AND COMMENT; BLUEPRINT ISSUANCE.] The 
  9.31  commissioner shall provide notice of all public meetings to 
  9.32  discuss the proposed blueprint and allow opportunity for written 
  9.33  comment prior to issuing the final blueprint.  After review by 
  9.34  the administrator, the commissioner shall publish the final 
  9.35  energy blueprint in the State Register within four months of 
  9.36  issuing the draft blueprint. 
 10.1      Sec. 10.  [216B.019] [REGIONAL ENERGY INFRASTRUCTURE 
 10.2   PLANNING.] 
 10.3      Subdivision 1.  [ESTABLISHING PLANNING REGIONS.] The 
 10.4   commission, after notice and opportunity for written comment, 
 10.5   shall establish geographic regional energy infrastructure 
 10.6   planning regions in the state by August 1, 2001.  Planning 
 10.7   regions may coincide with existing subregional planning areas 
 10.8   used by the regional electric reliability or regional 
 10.9   transmission organization serving Minnesota. 
 10.10     Subd. 2.  [PLANNING GROUP.] Each energy utility that 
 10.11  operates in an identified region shall participate in the 
 10.12  regional energy infrastructure planning group.  Each regional 
 10.13  group must include as voting members an equal number of 
 10.14  representatives of energy utilities, and representatives from 
 10.15  counties in the identified region, appointed by the county board.
 10.16     Subd. 3.  [PUBLIC MEETINGS.] Each regional energy 
 10.17  infrastructure planning group shall hold public meetings within 
 10.18  the region on a regular basis and provide public notice at least 
 10.19  14 calendar days in advance of a meeting. 
 10.20     Subd. 4.  [REPORT.] By December 31, 2001, and every two 
 10.21  years thereafter, each regional energy infrastructure planning 
 10.22  group shall submit a report to the commissioner that: 
 10.23     (1) identifies inadequacies in electric generation and 
 10.24  transmission within the region including any deficiencies as 
 10.25  defined in subdivision 5; 
 10.26     (2) lists alternative ways to address identified 
 10.27  inadequacies, taking into account the provisions of the state 
 10.28  energy security blueprint; 
 10.29     (3) identifies potential general and, to the extent known, 
 10.30  specific economic, environmental, and social issues associated 
 10.31  with each alternative; and 
 10.32     (4) recommends alternatives to address identified 
 10.33  inadequacies and deficiencies that ensure the reliability and 
 10.34  security of the energy system in the region, while minimizing 
 10.35  environmental and social impacts.  In making recommendations, 
 10.36  the planning group shall identify critical needs.  For the 
 11.1   purposes of this clause, "critical needs" are those projects 
 11.2   that are necessary to maintain reliable electric service to 
 11.3   Minnesota consumers that meet or exceed the most stringent 
 11.4   applicable state or regional reliability standards. 
 11.5      Subd. 5.  [DEFICIENCY.] (a) "Deficiency" means a condition, 
 11.6   or set of conditions, that materially limit the adequacy of 
 11.7   electric supply, efficiency of electric service, or reliability 
 11.8   of electric service to an electric utility's customers in the 
 11.9   state that may require construction of a generation or 
 11.10  transmission project. 
 11.11     (b) Within 90 days of identifying a deficiency in its 
 11.12  system, an electric utility shall give notice of the deficiency 
 11.13  to at least: 
 11.14     (1) the members of affected regional energy infrastructure 
 11.15  planning groups; 
 11.16     (2) officials of potentially affected local governments; 
 11.17  and 
 11.18     (3) the commissioner and the independent reliability 
 11.19  administrator. 
 11.20     (c) Notice of deficiency must be made before submitting (1) 
 11.21  an application for a certificate of need under section 216B.243 
 11.22  or (2) a request for environmental review of an energy project 
 11.23  to any governmental entity.  
 11.24     Sec. 11.  [EFFECTIVE DATES.] 
 11.25     Sections 2 and 3 are effective July 1, 2002.  The rest of 
 11.26  this article is effective the day following final enactment. 
 11.27                             ARTICLE 2
 11.28                  ESSENTIAL ENERGY INFRASTRUCTURE
 11.29     Section 1.  Minnesota Statutes 2000, section 116.07, 
 11.30  subdivision 4a, is amended to read: 
 11.31     Subd. 4a.  [PERMITS.] (a) The pollution control agency may 
 11.32  issue, continue in effect, or deny permits, under such 
 11.33  conditions as it may prescribe for the prevention of pollution, 
 11.34  for (1) the emission of air contaminants except for emissions 
 11.35  from electric generation stations, or for (2) the installation 
 11.36  or operation of any emission facility, air contaminant treatment 
 12.1   facility, treatment facility, potential air contaminant storage 
 12.2   facility, or storage facility, or any part thereof, or for (3) 
 12.3   the sources or emissions of noise pollution. 
 12.4      The pollution control agency may also issue, continue in 
 12.5   effect or deny permits, under such conditions as it may 
 12.6   prescribe for the prevention of pollution, for, (4) the 
 12.7   emissions of air contaminants from electric generation stations, 
 12.8   (5) the storage, collection, transportation, processing, or 
 12.9   disposal of waste, or for (6) the installation or operation of 
 12.10  any system or facility, or any part thereof, related to the 
 12.11  storage, collection, transportation, processing, or disposal of 
 12.12  waste. 
 12.13  The pollution control agency may revoke or modify any permit 
 12.14  issued under this subdivision and section 116.081 whenever it is 
 12.15  necessary, in the opinion of the agency, to prevent or abate 
 12.16  pollution. 
 12.17     (b) The pollution control agency has the authority for 
 12.18  approval over the siting, expansion, or operation of a solid 
 12.19  waste facility with regard to environmental issues.  However, 
 12.20  the agency's issuance of a permit does not release the permittee 
 12.21  from any liability, penalty, or duty imposed by any applicable 
 12.22  county ordinances.  Nothing in this chapter precludes, or shall 
 12.23  be construed to preclude, a county from enforcing land use 
 12.24  controls, regulations, and ordinances existing at the time of 
 12.25  the permit application and adopted pursuant to sections 366.10 
 12.26  to 366.181, 394.21 to 394.37, or 462.351 to 462.365, with regard 
 12.27  to the siting, expansion, or operation of a solid waste facility.
 12.28     Sec. 2.  Minnesota Statutes 2000, section 116C.52, 
 12.29  subdivision 4, is amended to read: 
 12.30     Subd. 4.  [HIGH VOLTAGE TRANSMISSION LINE.] "High voltage 
 12.31  transmission line" means a conductor of electric energy and 
 12.32  associated facilities designed for and capable of operation at a 
 12.33  nominal voltage of 200 100 kilovolts or more, except that the 
 12.34  board, by rule, may exempt lines pursuant to section 116C.57, 
 12.35  subdivision 5. 
 12.36     Sec. 3.  Minnesota Statutes 2000, section 116C.53, 
 13.1   subdivision 3, is amended to read: 
 13.2      Subd. 3.  [INTERSTATE ROUTES.] (a) If a route is proposed 
 13.3   in two or more states, the board shall attempt to reach 
 13.4   agreement with affected states on the entry and exit points 
 13.5   prior to authorizing the construction of the route. The board, 
 13.6   in discharge of its duties pursuant to sections 116C.51 to 
 13.7   116C.69 may make joint investigations, hold joint hearings 
 13.8   within or without the state, and issue joint or concurrent 
 13.9   orders in conjunction or concurrence with any official or agency 
 13.10  of any state or of the United States.  The board may negotiate 
 13.11  and enter into any agreements or compacts with agencies of other 
 13.12  states, pursuant to any consent of Congress, for cooperative 
 13.13  efforts in certifying the construction, operation, and 
 13.14  maintenance of large electric power facilities in accord with 
 13.15  the purposes of sections 116C.51 to 116C.69 and for the 
 13.16  enforcement of the respective state laws regarding such these 
 13.17  facilities. 
 13.18     (b) The board may not issue a route permit for the 
 13.19  Minnesota portion of an interstate high voltage transmission 
 13.20  line unless the applicant has received a certificate of need 
 13.21  from the public utilities commission.  
 13.22     Sec. 4.  Minnesota Statutes 2000, section 116C.57, 
 13.23  subdivision 1, is amended to read: 
 13.24     Subdivision 1.  [DESIGNATION OF SITES SUITABLE FOR SPECIFIC 
 13.25  FACILITIES; REPORTS SITE PERMIT.] A utility must apply to the 
 13.26  board in a form and manner prescribed by the board for 
 13.27  designation of a specific site for a specific size and type of 
 13.28  facility.  The application shall contain at least two proposed 
 13.29  sites.  In the event a utility proposes a site not included in 
 13.30  the board's inventory of study areas, the utility shall specify 
 13.31  the reasons for the proposal and shall make an evaluation of the 
 13.32  proposed site based upon the planning policies, criteria and 
 13.33  standards specified in the inventory.  Pursuant to sections 
 13.34  116C.57 to 116C.60, the board shall study and evaluate any site 
 13.35  proposed by a utility and any other site the board deems 
 13.36  necessary which was proposed in a manner consistent with rules 
 14.1   adopted by the board concerning the form, content, and 
 14.2   timeliness of proposals for alternate sites.  No site 
 14.3   designation shall be made in violation of the site selection 
 14.4   standards established in section 116C.55.  The board shall 
 14.5   indicate the reasons for any refusal and indicate changes in 
 14.6   size or type of facility necessary to allow site designation. 
 14.7   Within a year after the board's acceptance of a utility's 
 14.8   application, the board shall decide in accordance with the 
 14.9   criteria specified in section 116C.55, subdivision 2, the 
 14.10  responsibilities, procedures and considerations specified in 
 14.11  section 116C.57, subdivision 4, and the considerations in 
 14.12  chapter 116D which proposed site is to be designated.  The board 
 14.13  may extend for just cause the time limitation for its decision 
 14.14  for a period not to exceed six months.  When the board 
 14.15  designates a site, it shall issue a certificate of site 
 14.16  compatibility to the utility with any appropriate conditions.  
 14.17  The board shall publish a notice of its decision in the State 
 14.18  Register within 30 days of site designation. No person may 
 14.19  construct a large electric power generating plant shall be 
 14.20  constructed except on without a site designated by permit from 
 14.21  the board or a county.  A large electric generating plant may be 
 14.22  constructed only on either (1) a site approved by the board 
 14.23  under this section or section 116C.575, or (2) a site designated 
 14.24  by a county using terms, conditions, procedures, and standards 
 14.25  no less stringent than those imposed and used by the board. 
 14.26     Sec. 5.  Minnesota Statutes 2000, section 116C.57, 
 14.27  subdivision 2, is amended to read: 
 14.28     Subd. 2.  [DESIGNATION OF ROUTES; PROCEDURE ROUTE PERMIT.] 
 14.29  A utility shall apply to the board in a form and manner 
 14.30  prescribed by the board for a permit for the construction of a 
 14.31  high voltage transmission line.  The application shall contain 
 14.32  at least two proposed routes.  Pursuant to sections 116C.57 to 
 14.33  116C.60, the board shall study, and evaluate the type, design, 
 14.34  routing, right-of-way preparation and facility construction of 
 14.35  any route proposed in a utility's application and any other 
 14.36  route the board deems necessary which was proposed in a manner 
 15.1   consistent with rules adopted by the board concerning the form, 
 15.2   content, and timeliness of proposals for alternate routes 
 15.3   provided, however, that the board shall identify the alternative 
 15.4   routes prior to the commencement of public hearings thereon 
 15.5   pursuant to section 116C.58.  Within one year after the board's 
 15.6   acceptance of a utility's application, the board shall decide in 
 15.7   accordance with the criteria and standards specified in section 
 15.8   116C.55, subdivision 2, and the considerations specified in 
 15.9   section 116C.57, subdivision 4, which proposed route is to be 
 15.10  designated.  The board may extend for just cause the time 
 15.11  limitation for its decision for a period not to exceed 90 days.  
 15.12  When the board designates a route, it shall issue a permit for 
 15.13  the construction of a high voltage transmission line specifying 
 15.14  the type, design, routing, right-of-way preparation and facility 
 15.15  construction it deems necessary and with any other appropriate 
 15.16  conditions.  The board may order the construction of high 
 15.17  voltage transmission line facilities which are capable of 
 15.18  expansion in transmission capacity through multiple circuiting 
 15.19  or design modifications.  The board shall publish a notice of 
 15.20  its decision in the state register within 30 days of issuance of 
 15.21  the permit.  (a) No person may construct a high voltage 
 15.22  transmission line shall be constructed except on without a route 
 15.23  designated by permit from the board or by a county pursuant to 
 15.24  paragraph (b), unless it was exempted pursuant to subdivision 
 15.25  5.  A high voltage transmission line may be constructed only 
 15.26  along a route approved by the board under this section or 
 15.27  section 116C.575, or by a county pursuant to paragraph (b). 
 15.28     (b) A high voltage transmission line of between 100 and 200 
 15.29  kilovolts may be permitted and routed by a county using terms, 
 15.30  conditions, procedures, and standards no less stringent than 
 15.31  those imposed and used by the board, unless the county requests 
 15.32  the board to route the proposed line. 
 15.33     Sec. 6.  Minnesota Statutes 2000, section 116C.57, is 
 15.34  amended by adding a subdivision to read: 
 15.35     Subd. 2a.  [APPLICATION.] (a) A person seeking to construct 
 15.36  a large electric power generating plant or a high voltage 
 16.1   transmission line shall apply to the board for a site permit or 
 16.2   route permit.  The application must contain any information 
 16.3   required by the board and must specify: 
 16.4      (1) whether the applicant is required to receive a 
 16.5   certificate of need for the proposed project; 
 16.6      (2) whether the applicant is required to comply with 
 16.7   section 216B.019, subdivision 5, and has complied; 
 16.8      (3) whether the proposed project was identified, discussed, 
 16.9   and considered by the relevant regional energy infrastructure 
 16.10  planning group and the result of that consideration. 
 16.11     (b) The applicant shall propose at least two sites for a 
 16.12  large electric power generating plant and two routes for a high 
 16.13  voltage transmission line. 
 16.14     (c) The chair of the board shall determine whether an 
 16.15  application is complete and advise the applicant of any 
 16.16  deficiencies. 
 16.17     Sec. 7.  Minnesota Statutes 2000, section 116C.57, is 
 16.18  amended by adding a subdivision to read: 
 16.19     Subd. 2b.  [NOTICE OF APPLICATION.] Within 15 days after 
 16.20  submitting an application to the board, the applicant shall 
 16.21  publish notice of the application in a legal newspaper of 
 16.22  general circulation in each county in which the site or route is 
 16.23  proposed and send a copy of the application by certified mail to 
 16.24  any regional development commission, county, incorporated 
 16.25  municipality, and town in which the site or route is proposed.  
 16.26  Within the same 15 days, the applicant shall also send a notice 
 16.27  of the submission of the application and description of the 
 16.28  proposed project to each owner whose property is adjacent to any 
 16.29  of the proposed sites for the power plant or along any of the 
 16.30  proposed routes for the transmission line.  The notice must 
 16.31  identify a location where a copy of the application can be 
 16.32  reviewed.  For the purpose of giving mailed notice under this 
 16.33  subdivision, owners are those shown on the records of the county 
 16.34  auditor or, in any county where tax statements are mailed by the 
 16.35  county treasurer, on the records of the county treasurer, but 
 16.36  other appropriate records may be used for this purpose.  The 
 17.1   failure to give mailed notice to a property owner, or defects in 
 17.2   the notice, does not invalidate the proceedings, provided a bona 
 17.3   fide attempt to comply with this subdivision has been made.  
 17.4   Within the same 15 days, the applicant shall also send the same 
 17.5   notice of the submission of the application and description of 
 17.6   the proposed project to those persons who have requested to be 
 17.7   placed on a list maintained by the board for receiving notice of 
 17.8   proposed large electric generating power plants and high voltage 
 17.9   transmission lines. 
 17.10     Sec. 8.  Minnesota Statutes 2000, section 116C.57, is 
 17.11  amended by adding a subdivision to read: 
 17.12     Subd. 2c.  [ENVIRONMENTAL REVIEW.] (a) After a complete 
 17.13  application has been submitted, an environmental impact 
 17.14  statement must be prepared by the board for each proposed large 
 17.15  electric generating plant and for each proposed high voltage 
 17.16  transmission line.  
 17.17     (b) The board shall not consider the no-build alternative 
 17.18  for any project that is required to have a certificate of need 
 17.19  from the public utilities commission.  
 17.20     (c) No other state environmental review documents are 
 17.21  required.  
 17.22     (d) The board shall study and evaluate any site or route 
 17.23  proposed by an applicant, in addition to any other site or route 
 17.24  the board deems necessary that was proposed in a manner 
 17.25  consistent with rules adopted by the board concerning the form, 
 17.26  content, and timeliness of proposals for alternate sites or 
 17.27  routes. 
 17.28     Sec. 9.  Minnesota Statutes 2000, section 116C.57, is 
 17.29  amended by adding a subdivision to read: 
 17.30     Subd. 2d.  [PUBLIC HEARING.] The board and the independent 
 17.31  reliability administrator shall hold a joint public hearing on 
 17.32  an application for a site permit for a large electric power 
 17.33  generating plant or a route permit for a high voltage 
 17.34  transmission line.  A hearing held for designating a site or 
 17.35  route must be conducted by an administrative law judge from the 
 17.36  office of administrative hearings under the contested case 
 18.1   procedures of chapter 14.  Notice of the hearing must be given 
 18.2   by the board at least ten days in advance but no earlier than 45 
 18.3   days prior to the commencement of the hearing.  Notice must be 
 18.4   by publication in a legal newspaper of general circulation in 
 18.5   the county in which the public hearing is to be held and by 
 18.6   certified mail to chief executives of the regional development 
 18.7   commissions, counties, organized towns, townships, and the 
 18.8   incorporated municipalities in which a site or route is 
 18.9   proposed.  A person may appear at the hearing and offer 
 18.10  testimony and exhibits without the necessity of intervening as a 
 18.11  formal party to the proceeding.  The administrative law judge 
 18.12  may allow a person to ask questions of other witnesses.  The 
 18.13  administrative law judge shall hold a portion of the hearing in 
 18.14  the area where the power plant or transmission line is proposed 
 18.15  to be located. 
 18.16     Sec. 10.  Minnesota Statutes 2000, section 116C.57, 
 18.17  subdivision 4, is amended to read: 
 18.18     Subd. 4.  [CONSIDERATIONS IN DESIGNATING SITES AND 
 18.19  ROUTES.] (a) To facilitate the study, research, evaluation, and 
 18.20  designation of sites and routes, the board shall be guided by, 
 18.21  but not limited to, the following responsibilities, procedures, 
 18.22  and considerations: 
 18.23     (1) evaluation of research and investigations relating to 
 18.24  the effects on land, water, and air resources of large electric 
 18.25  power generating plants and high voltage transmission line 
 18.26  routes and the effects of water and air discharges and electric 
 18.27  fields resulting from such facilities on public health and 
 18.28  welfare, vegetation, animals, materials, and aesthetic values, 
 18.29  including base line studies, predictive modeling, and monitoring 
 18.30  of the water and air mass at proposed and operating sites and 
 18.31  routes, evaluation of new or improved methods for minimizing 
 18.32  adverse impacts of water and air discharges and other matters 
 18.33  pertaining to the effects of power plants on the water and air 
 18.34  environment; 
 18.35     (2) environmental evaluation of sites and routes proposed 
 18.36  for future development and expansion and their relationship to 
 19.1   the land, water, air, and human resources of the state; 
 19.2      (3) evaluation of the effects of new electric power 
 19.3   generation and transmission technologies and systems related to 
 19.4   power plants designed to minimize adverse environmental effects; 
 19.5      (4) evaluation of the potential for beneficial uses of 
 19.6   waste energy from proposed large electric power generating 
 19.7   plants; 
 19.8      (5) analysis of the direct and indirect economic impact of 
 19.9   proposed sites and routes including, but not limited to, 
 19.10  productive agricultural land lost or impaired; 
 19.11     (6) evaluation of adverse direct and indirect environmental 
 19.12  effects which that cannot be avoided should the proposed site 
 19.13  and route be accepted; 
 19.14     (7) evaluation of alternatives to the applicant's proposed 
 19.15  site or route proposed pursuant to subdivisions 1 and 2; 
 19.16     (8) evaluation of potential routes which that would use or 
 19.17  parallel existing railroad and highway rights-of-way; 
 19.18     (9) evaluation of governmental survey lines and other 
 19.19  natural division lines of agricultural land so as to minimize 
 19.20  interference with agricultural operations; 
 19.21     (10) evaluation of the future needs for additional high 
 19.22  voltage transmission lines in the same general area as any 
 19.23  proposed route, and the advisability of ordering the 
 19.24  construction of structures capable of expansion in transmission 
 19.25  capacity through multiple circuiting or design modifications; 
 19.26     (11) evaluation of irreversible and irretrievable 
 19.27  commitments of resources should the proposed site or route be 
 19.28  approved; and 
 19.29     (12) where when appropriate, consideration of problems 
 19.30  raised by other state and federal agencies and local entities. 
 19.31     (13) (b) If the board's rules are substantially similar to 
 19.32  existing rules and regulations of a federal agency to which the 
 19.33  utility in the state is subject, the federal rules and 
 19.34  regulations shall must be applied by the board. 
 19.35     (14) (c) No site or route shall may be designated which 
 19.36  violates if to do so would violate state agency rules. 
 20.1      Sec. 11.  Minnesota Statutes 2000, section 116C.57, is 
 20.2   amended by adding a subdivision to read: 
 20.3      Subd. 7.  [TIMING.] The board shall make a final decision 
 20.4   on an application within 60 days after receipt of the report of 
 20.5   the administrative law judge.  A final decision on the request 
 20.6   for a site permit or route permit shall be made within one year 
 20.7   after the chair's determination that an application is 
 20.8   complete.  The time for the final decision may be extended for 
 20.9   up to 90 days for good cause and if all parties agree. 
 20.10     Sec. 12.  Minnesota Statutes 2000, section 116C.57, is 
 20.11  amended by adding a subdivision to read: 
 20.12     Subd. 8.  [FINAL DECISION.] (a) A site permit may not be 
 20.13  issued in violation of the site selection standards and criteria 
 20.14  established in this section and in rules adopted by the board.  
 20.15  The board shall indicate the reasons for any refusal and 
 20.16  indicate changes in size or type of facility necessary to allow 
 20.17  site designation.  When the board designates a site, it shall 
 20.18  issue a site permit to the applicant with any appropriate 
 20.19  conditions.  The board shall publish a notice of its decision in 
 20.20  the State Register within 30 days of issuing the site permit. 
 20.21     (b) A route permit may not be issued in violation of the 
 20.22  route selection standards and criteria established in this 
 20.23  section and in rules adopted by the board.  When the route is 
 20.24  designated, the permit issued for the construction of the 
 20.25  facility must specify the type, design, routing, right-of-way 
 20.26  preparation, and facility construction deemed necessary and any 
 20.27  other appropriate conditions.  The board may order the 
 20.28  construction of high voltage transmission line facilities that 
 20.29  are capable of expansion in transmission capacity through 
 20.30  multiple circuiting or design modifications.  The board shall 
 20.31  publish a notice of its decision in the State Register within 30 
 20.32  days of issuing the permit. 
 20.33     Sec. 13.  [116C.575] [ALTERNATIVE REVIEW OF APPLICATIONS.] 
 20.34     Subdivision 1.  [ALTERNATIVE REVIEW.] An applicant who 
 20.35  seeks a site permit or route permit for one of the projects 
 20.36  identified in this section may petition the board to be allowed 
 21.1   to follow the procedures in this section rather than the 
 21.2   procedures in section 116C.57.  The board shall grant the 
 21.3   petition within 30 days unless the board finds good cause for 
 21.4   denial.  
 21.5      Subd. 2.  [APPLICABLE PROJECTS.] The requirements and 
 21.6   procedures in this section may apply to the following projects: 
 21.7      (1) large electric power generating plants with a capacity 
 21.8   of between 50 and 80 megawatts regardless of fuel; 
 21.9      (2) large electric power generating plants powered by 
 21.10  natural gas as its primary fuel; 
 21.11     (3) projects to retrofit or repower an existing large 
 21.12  electric power generating plant to one burning primarily natural 
 21.13  gas or other similar clean fuel; 
 21.14     (4) any natural gas peaking facility designed for or 
 21.15  capable of storing on a single site more than 100,000 gallons of 
 21.16  liquefied natural gas or synthetic gas; 
 21.17     (5) high voltage transmission lines of between 100 and 200 
 21.18  kilovolts; 
 21.19     (6) high voltage transmission lines in excess of 200 
 21.20  kilovolts less than five miles in length in Minnesota; and 
 21.21     (7) high voltage transmission lines in excess of 200 
 21.22  kilovolts if at least 80 percent of the distance of the line in 
 21.23  Minnesota will be located parallel or along existing high 
 21.24  voltage transmission line right-of-way. 
 21.25     Subd. 3.  [APPLICATION.] The applicant for a site 
 21.26  certificate or route permit for any of the projects listed in 
 21.27  subdivision 2 who chooses to follow these procedures shall 
 21.28  submit information the board may require, but the applicant is 
 21.29  not required to propose a second site or route for the project.  
 21.30  The applicant shall identify in the application any other sites 
 21.31  or routes that were rejected by the applicant and the board may 
 21.32  identify additional sites or routes to consider during the 
 21.33  processing of the application.  The chair of the board shall 
 21.34  determine whether an application is complete and advise the 
 21.35  applicant of any deficiencies. 
 21.36     Subd. 4.  [NOTICE OF APPLICATION.] On submitting an 
 22.1   application under this section, the applicant shall provide the 
 22.2   same notice as required by section 116C.57, subdivision 4. 
 22.3      Subd. 5.  [ENVIRONMENTAL REVIEW.] For the projects 
 22.4   identified in subdivision 2 and following these procedures, the 
 22.5   board shall prepare an environmental assessment worksheet.  The 
 22.6   board shall include as part of the environmental assessment 
 22.7   worksheet alternative sites or routes identified by the board 
 22.8   and shall address mitigating measures for all of the sites or 
 22.9   routes considered.  The environmental assessment worksheet is 
 22.10  the only state environmental review document required to be 
 22.11  prepared on the project. 
 22.12     Subd. 6.  [PUBLIC MEETING.] The board and the independent 
 22.13  reliability administrator shall hold a joint public meeting in 
 22.14  the area where the facility is proposed to be located.  The 
 22.15  board shall give notice of the public meeting in the same manner 
 22.16  as notice for a public hearing.  The board shall provide 
 22.17  opportunity at the public meeting for any person to present 
 22.18  comments and to ask questions of the applicant and board staff.  
 22.19  The board shall also afford interested persons an opportunity to 
 22.20  submit written comments into the record. 
 22.21     Subd. 7.  [TIMING.] The board shall make a final decision 
 22.22  on an application within 60 days after completion of the public 
 22.23  meeting.  A final decision on the request for a site permit or 
 22.24  route permit under this section must be made within six months 
 22.25  after the chair's determination that an application is 
 22.26  complete.  The time for the final decision may be extended for 
 22.27  up to 45 days for good cause and if all parties agree. 
 22.28     Subd. 8.  [CONSIDERATIONS.] The considerations in section 
 22.29  116C.57, subdivision 4, apply to any projects subject to this 
 22.30  section. 
 22.31     Subd. 9.  [FINAL DECISION.] (a) A site permit may not be 
 22.32  issued in violation of the site selection standards and criteria 
 22.33  established in this section and in rules adopted by the board.  
 22.34  The board shall indicate the reasons for any refusal and 
 22.35  indicate changes in size or type of facility necessary to allow 
 22.36  site designation.  When the board designates a site, it shall 
 23.1   issue a site permit to the applicant with any appropriate 
 23.2   conditions.  The board shall publish a notice of its decision in 
 23.3   the State Register within 30 days of issuance of the site permit.
 23.4      (b) A route designation may not be made in violation of the 
 23.5   route selection standards and criteria established in this 
 23.6   section and in rules adopted by the board.  When the board 
 23.7   designates a route, it shall issue a permit for the construction 
 23.8   of a high voltage transmission line specifying the type, design, 
 23.9   routing, right-of-way preparation, and facility construction it 
 23.10  deems necessary and with any other appropriate conditions.  The 
 23.11  board may order the construction of high voltage transmission 
 23.12  line facilities that are capable of expansion in transmission 
 23.13  capacity through multiple circuiting or design modifications.  
 23.14  The board shall publish a notice of its decision in the State 
 23.15  Register within 30 days of issuance of the permit. 
 23.16     Sec. 14.  [116C.576] [EMERGENCY PERMIT.] 
 23.17     (a) Any utility whose electric power system requires the 
 23.18  immediate construction of a large electric power generating 
 23.19  plant or high voltage transmission line due to a major 
 23.20  unforeseen event may apply to the board for an emergency permit 
 23.21  after providing notice in writing to the public utilities 
 23.22  commission of the major unforeseen event and the need for 
 23.23  immediate construction.  The permit must be issued in a timely 
 23.24  manner, no later than 195 days after the board's acceptance of 
 23.25  the application and upon a finding by the board that (1) a 
 23.26  demonstrable emergency exists, (2) the emergency requires 
 23.27  immediate construction, and (3) adherence to the procedures and 
 23.28  time schedules specified in section 116C.57 would jeopardize the 
 23.29  utility's electric power system or would jeopardize the 
 23.30  utility's ability to meet the electric needs of its customers in 
 23.31  an orderly and timely manner. 
 23.32     (b) A public hearing to determine if an emergency exists 
 23.33  must be held within 90 days of the application.  The board, 
 23.34  after notice and hearing, shall adopt rules specifying the 
 23.35  criteria for emergency certification.  
 23.36     Sec. 15.  Minnesota Statutes 2000, section 116C.58, is 
 24.1   amended to read: 
 24.2      116C.58 [PUBLIC HEARINGS; NOTICE ANNUAL HEARING.] 
 24.3      The board shall hold an annual public hearing at a time and 
 24.4   place prescribed by rule in order to afford interested persons 
 24.5   an opportunity to be heard regarding its inventory of study 
 24.6   areas and any other aspects of the board's activities and duties 
 24.7   or policies specified in sections 116C.51 to 116C.69.  The board 
 24.8   shall hold at least one public hearing in each county where a 
 24.9   site or route is being considered for designation pursuant to 
 24.10  section 116C.57.  Notice and agenda of public hearings and 
 24.11  public meetings of the board held in each county shall be given 
 24.12  by the board at least ten days in advance but no earlier than 45 
 24.13  days prior to such hearings or meetings.  Notice shall be by 
 24.14  publication in a legal newspaper of general circulation in the 
 24.15  county in which the public hearing or public meeting is to be 
 24.16  held and by certified mailed notice to chief executives of the 
 24.17  regional development commissions, counties, organized towns and 
 24.18  the incorporated municipalities in which a site or route is 
 24.19  proposed.  All hearings held for designating a site or route or 
 24.20  for exempting a route shall be conducted by an administrative 
 24.21  law judge from the office of administrative hearings pursuant to 
 24.22  the contested case procedures of chapter 14.  Any person may 
 24.23  appear at the hearings and present testimony and exhibits and 
 24.24  may question witnesses without the necessity of intervening as a 
 24.25  formal party to the proceedings. any matters relating to the 
 24.26  siting of large electric generating power plants and routing of 
 24.27  high voltage transmission lines.  At the meeting, the board 
 24.28  shall advise the public of the permits issued by the board in 
 24.29  the past year.  The board shall provide at least ten days' 
 24.30  notice, but no more than 45 days' notice, of the annual meeting 
 24.31  by mailing notice to those persons who have requested notice and 
 24.32  by publication in the board's "EQB Monitor." 
 24.33     Sec. 16.  Minnesota Statutes 2000, section 116C.59, 
 24.34  subdivision 1, is amended to read: 
 24.35     Subdivision 1.  [ADVISORY TASK FORCE LOCAL PLANNING 
 24.36  COMMISSIONS.] The board may appoint one or more advisory task 
 25.1   forces shall confer with affected local planning commissions to 
 25.2   assist it in carrying out its duties.  Task forces appointed to 
 25.3   evaluate sites or routes considered for designation shall be 
 25.4   comprised of as many persons as may be designated by the board, 
 25.5   but at least one representative from each of the following:  
 25.6   Regional development commissions, counties and municipal 
 25.7   corporations and one town board member from each county in which 
 25.8   a site or route is proposed to be located.  No officer, agent, 
 25.9   or employee of a utility shall serve on an advisory task force.  
 25.10  Reimbursement for expenses incurred shall be made pursuant to 
 25.11  the rules governing state employees.  The task forces expire as 
 25.12  provided in section 15.059, subdivision 6. 
 25.13     Sec. 17.  Minnesota Statutes 2000, section 116C.60, is 
 25.14  amended to read: 
 25.15     116C.60 [PUBLIC MEETINGS; TRANSCRIPT OF PROCEEDINGS; 
 25.16  WRITTEN RECORDS.] 
 25.17     Meetings of the board, including hearings, shall must be 
 25.18  open to the public.  Minutes shall must be kept of board 
 25.19  meetings and a complete record of public hearings shall be 
 25.20  kept.  All books, records, files, and correspondence of the 
 25.21  board shall must be available for public inspection at any 
 25.22  reasonable time.  The council shall board is also be subject to 
 25.23  chapter 13D. 
 25.24     Sec. 18.  Minnesota Statutes 2000, section 216B.16, is 
 25.25  amended by adding a subdivision to read: 
 25.26     Subd. 17.  [DISTRIBUTED GENERATION TARIFF.] (a) In order to 
 25.27  facilitate and encourage the use of distributed generation, each 
 25.28  public utility providing electric service at retail shall file a 
 25.29  distributed generation tariff for commission approval or 
 25.30  approval with modification.  
 25.31     (b) The commission may approve a tariff that it finds: 
 25.32     (1) provides for the low-cost, safe, and standardized 
 25.33  interconnection, consistent with sections 216B.68 to 216B.75, of 
 25.34  customer-owned distributed generation facilities (i) consisting 
 25.35  of fuel cells and microturbines fueled by natural gas, renewable 
 25.36  fuels, or other similarly clean fuels, by wind, or by 
 26.1   photo-voltaics; (ii) with a capacity of two megawatts or less; 
 26.2   (iii) owned by small-business or residential customers; and (iv) 
 26.3   constructed on-site; 
 26.4      (2) encourages and compensates for the addition of 
 26.5   distributed generation power resources while reducing the cost 
 26.6   to the utility's customers for energy, capacity, transmission 
 26.7   and distribution; 
 26.8      (3) minimizes and avoids tariff-related increases in the 
 26.9   rates of customers not taking service under the distributed 
 26.10  generation tariff; and 
 26.11     (4) allows for reasonable terms and conditions, consistent 
 26.12  with the cost and operating characteristics of the various 
 26.13  technologies, so that the utility can reasonably rely upon the 
 26.14  equipment to be operational when called upon. 
 26.15     (c) The commission may develop financial incentives based 
 26.16  on a utility's performance in encouraging residential and small 
 26.17  business customers to participate in on-site generation. 
 26.18     Sec. 19.  Minnesota Statutes 2000, section 216B.2421, 
 26.19  subdivision 2, is amended to read: 
 26.20     Subd. 2.  [LARGE ENERGY FACILITY.] "Large energy facility" 
 26.21  means: 
 26.22     (1) any electric power generating plant or combination of 
 26.23  plants at a single site with a combined capacity of 80,000 
 26.24  kilowatts or more, or any facility of 50,000 kilowatts or more 
 26.25  which requires oil, natural gas, or natural gas liquids as a 
 26.26  fuel and for which an installation permit has not been applied 
 26.27  for by May 19, 1977 pursuant to Minn. Reg. APC 3(a); 
 26.28     (2) any high voltage transmission line with a capacity of 
 26.29  200 100 kilovolts or more and (i) with more than 50 ten miles 
 26.30  of its length in Minnesota, or (ii) any of its length in 
 26.31  Minnesota and that crosses the state line; or, any high voltage 
 26.32  transmission line with a capacity of 300 kilovolts or more with 
 26.33  more than 25 miles of its length in Minnesota; 
 26.34     (3) any pipeline greater than six inches in diameter and 
 26.35  having more than 50 miles of its length in Minnesota used for 
 26.36  the transportation of coal, crude petroleum or petroleum fuels 
 27.1   or oil or their derivatives; 
 27.2      (4) any pipeline for transporting natural or synthetic gas 
 27.3   at pressures in excess of 200 pounds per square inch with more 
 27.4   than 50 miles of its length in Minnesota; 
 27.5      (5) any facility designed for or capable of storing on a 
 27.6   single site more than 100,000 gallons of liquefied natural gas 
 27.7   or synthetic gas; 
 27.8      (6) any underground gas storage facility requiring permit 
 27.9   pursuant to section 103I.681; 
 27.10     (7) any nuclear fuel processing or nuclear waste storage or 
 27.11  disposal facility; and 
 27.12     (8) any facility intended to convert any material into any 
 27.13  other combustible fuel and having the capacity to process in 
 27.14  excess of 75 tons of the material per hour. 
 27.15     Sec. 20.  Minnesota Statutes 2000, section 216B.2421, is 
 27.16  amended by adding a subdivision to read: 
 27.17     Subd. 4.  [MODIFYING EXISTING LARGE ENERGY FACILITY.] 
 27.18  Refurbishing or upgrading an existing large energy facility 
 27.19  through the replacement or addition of facility components does 
 27.20  not require a certificate of need under section 216B.243, unless 
 27.21  the changes lead to (1) a capacity increase of more than 100 
 27.22  megawatts, or ten percent of existing capacity, whichever is 
 27.23  greater, or (2) operation at more than 50 percent higher voltage.
 27.24     Sec. 21.  Minnesota Statutes 2000, section 216B.243, 
 27.25  subdivision 2, is amended to read: 
 27.26     Subd. 2.  [CERTIFICATE REQUIRED.] (a) Except as provided in 
 27.27  paragraph (b), no large energy facility shall may be sited or 
 27.28  constructed in Minnesota without the issuance of a certificate 
 27.29  of need by the commission pursuant to sections 216C.05 to 
 27.30  216C.30 and this section and consistent with the criteria for 
 27.31  assessment of need. 
 27.32     (b) Notwithstanding paragraph (a), a large energy facility 
 27.33  that is a generation plant or a natural gas peaking facility not 
 27.34  owned by a public or municipal utility or cooperative electric 
 27.35  association and that is not to be included in the utility's or 
 27.36  association's rate base does not need a certificate of need 
 28.1   under this section. 
 28.2      Sec. 22.  Minnesota Statutes 2000, section 216B.243, is 
 28.3   amended by adding a subdivision to read: 
 28.4      Subd. 2a.  [PUBLIC PURPOSE DESIGNATION.] (a) When filing 
 28.5   for a certificate of need under this section, an applicant may 
 28.6   also petition the commission to designate the proposed large 
 28.7   energy facility a public purpose project.  The commission shall 
 28.8   approve or reject the petition at the same time the commission 
 28.9   renders its decision under subdivision 5.  Notwithstanding 
 28.10  section 116C.63 or any other law to the contrary, eminent domain 
 28.11  authority may not be used in constructing a large energy 
 28.12  facility unless the commission designates the facility a public 
 28.13  purpose project.  The value paid for property in the exercise of 
 28.14  eminent domain authority may be structured so as to provide for 
 28.15  the payment of a portion of the revenue derived from the large 
 28.16  energy facility over a period of years, rather than a lump sum 
 28.17  payment at the time the property is taken. 
 28.18     (b) In deciding whether to designate a proposed large 
 28.19  energy facility as a public purpose project, the commission 
 28.20  shall consider whether the proposed facility: 
 28.21     (1) remedies a condition, or set of conditions, that 
 28.22  materially limit the adequacy of electric supply, efficiency of 
 28.23  electric service, or reliability of electric service to 
 28.24  Minnesota consumers; 
 28.25     (2) was identified as a critical need by the relevant 
 28.26  regional energy infrastructure planning group; 
 28.27     (3) is consistent with all relevant state goals and 
 28.28  strategies approved by the legislature under section 216B.017; 
 28.29  and 
 28.30     (4) is otherwise in the public interest. 
 28.31     Sec. 23.  Minnesota Statutes 2000, section 216B.243, 
 28.32  subdivision 3, is amended to read: 
 28.33     Subd. 3.  [SHOWING REQUIRED FOR CONSTRUCTION.] No (a) A 
 28.34  proposed large energy facility shall may not be certified for 
 28.35  construction unless the applicant can show that demand for 
 28.36  electricity cannot be met more cost-effectively through energy 
 29.1   conservation and load-management measures and unless the 
 29.2   applicant has otherwise justified its need.  
 29.3      (b) In assessing need, the commission shall evaluate: 
 29.4      (1) the accuracy of the long-range energy demand forecasts 
 29.5   on which the necessity for the facility is based; 
 29.6      (2) the effect of existing or possible energy conservation 
 29.7   programs under sections 216C.05 to 216C.30 and this section or 
 29.8   other federal or state legislation on long-term energy demand; 
 29.9      (3) the relationship of the proposed facility to overall 
 29.10  state and regional energy needs, as described in the most recent 
 29.11  state energy policy and conservation report prepared under 
 29.12  section 216C.18 including consideration of (i) the most recent 
 29.13  state energy security blueprint under section 216B.015, (ii) the 
 29.14  most recent relevant regional energy infrastructure planning 
 29.15  group report under section 216B.019, and (iii) information from 
 29.16  federal and regional reliability organizations, regional 
 29.17  transmission organizations, and other relevant sources; 
 29.18     (4) promotional activities that may have given rise to the 
 29.19  demand for this facility; 
 29.20     (5) socially beneficial uses of the output (3) 
 29.21  environmental and socioeconomic benefits of this facility, 
 29.22  including its uses to protect or enhance environmental quality, 
 29.23  to increase reliability of energy supply in Minnesota and the 
 29.24  region, and to induce future development; 
 29.25     (6) the effects of the facility in inducing future 
 29.26  development; 
 29.27     (7) (4) possible alternatives for satisfying the energy 
 29.28  demand or transmission needs including but not limited to 
 29.29  potential for increased efficiency and upgrading of existing 
 29.30  energy generation and transmission facilities, load management 
 29.31  programs, and distributed generation; 
 29.32     (8) (5) the policies, rules, and regulations of other state 
 29.33  and federal agencies and local governments; and 
 29.34     (9) any (6) feasible combination of energy conservation 
 29.35  improvements, required under section 216B.241, sections 216C.05 
 29.36  to 216C.30, or other available conservation programs that can (i)
 30.1   reasonably replace a significant part or all of the energy to be 
 30.2   provided by the proposed facility, and (ii) compete with it 
 30.3   economically and in terms of reliability; and 
 30.4      (7) whether the proposed large energy facility was 
 30.5   recommended for construction by the relevant regional energy 
 30.6   infrastructure planning group. 
 30.7      Sec. 24.  Minnesota Statutes 2000, section 216B.243, 
 30.8   subdivision 4, is amended to read: 
 30.9      Subd. 4.  [APPLICATION FOR CERTIFICATE; HEARING.] Any 
 30.10  person proposing to construct a large energy facility shall 
 30.11  apply for a certificate of need prior to construction of the 
 30.12  facility.  The application shall be on forms and in a manner 
 30.13  established by the commission.  In reviewing each application 
 30.14  the commission shall hold at least one public hearing pursuant 
 30.15  to chapter 14.  The public hearing shall be held at a location 
 30.16  and hour reasonably calculated to be convenient for the public.  
 30.17  An objective of the public hearing shall be to obtain public 
 30.18  opinion on the necessity of granting a certificate of need.  The 
 30.19  commission shall designate a commission employee whose duty 
 30.20  shall be to facilitate citizen participation in the hearing 
 30.21  process.  If the commission and the environmental quality board 
 30.22  determine that a joint hearing on siting and need under this 
 30.23  subdivision and section 116C.57, subdivision 2d, is feasible, 
 30.24  more efficient, and may further the public interest, a joint 
 30.25  hearing under those subdivisions may be held. 
 30.26     Sec. 25.  [INSTRUCTION TO REVISOR.] 
 30.27     The revisor of statutes shall renumber Minnesota Statutes, 
 30.28  section 116C.57, subdivision 6, as section 116C.57, subdivision 
 30.29  9. 
 30.30     Sec. 26.  [REPEALER.] 
 30.31     Minnesota Statutes 2000, sections 116C.55; 116C.57, 
 30.32  subdivisions 3, 5, and 5a; and 116C.67, are repealed. 
 30.33     Sec. 27.  [EFFECTIVE DATES.] 
 30.34     This article is effective the day following final 
 30.35  enactment, except that those provisions referring or relating to 
 30.36  article 1, section 2 or 3, the independent reliability 
 31.1   administrator or the state reliability plan, are effective July 
 31.2   1, 2002.  Section 2 does not apply to any proposal for a 
 31.3   transmission line between 100 and 200 kilovolts that is pending 
 31.4   before a local unit of government as of February 1, 2001. 
 31.5                              ARTICLE 3 
 31.6                        REGULATORY FLEXIBILITY 
 31.7      Section 1.  Minnesota Statutes 2000, section 216B.16, 
 31.8   subdivision 7, is amended to read: 
 31.9      Subd. 7.  [ENERGY COST ADJUSTMENT.] (a) Notwithstanding any 
 31.10  other provision of this chapter, the commission may permit a 
 31.11  public utility to file rate schedules containing provisions for 
 31.12  the automatic adjustment of charges for public utility service 
 31.13  in direct relation to changes in:  (1) federally regulated 
 31.14  wholesale rates for energy delivered through interstate 
 31.15  facilities; (2) direct costs for natural gas delivered; or (3) 
 31.16  costs for fuel used in generation of electricity or the 
 31.17  manufacture of gas. 
 31.18     (b) In reviewing utility fuel purchases under this or any 
 31.19  other provision, the commission shall allow and encourage a 
 31.20  utility to have a combination of measures to manage price 
 31.21  volatility and risk, including but not limited to having an 
 31.22  appropriate share of the utility's supply come from long-term 
 31.23  and medium-term contracts, in order to minimize consumer 
 31.24  exposure to fuel price volatility. 
 31.25     Sec. 2.  [216B.169] [RENEWABLE AND HIGH EFFICIENCY ENERGY 
 31.26  RATE OPTIONS.] 
 31.27     (a) Each public utility, cooperative association, and 
 31.28  municipal utility shall offer its customers and shall advertise 
 31.29  the offer at least annually one or more options that allow a 
 31.30  customer to determine that a certain amount of the electricity 
 31.31  generated or purchased on behalf of the customer is (1) 
 31.32  renewable energy as defined in section 216B.2422, subdivision 1, 
 31.33  paragraph (c), or (2) high-efficiency, low-emissions, 
 31.34  distributed generation such as fuel cells and microturbines 
 31.35  fueled by a renewable fuel. 
 31.36     (b) Each public utility shall file an implementation plan 
 32.1   within 90 days of the effective date of this section to 
 32.2   implement paragraph (a).  
 32.3      (c) Rates charged to customers must be calculated using the 
 32.4   utility's or association's cost of acquiring the energy for the 
 32.5   customer and must be (1) the difference between the cost of 
 32.6   generating or purchasing the renewable energy and the cost of 
 32.7   generating or purchasing the same amount of nonrenewable energy; 
 32.8   and (2) distributed on a per kilowatt-hour basis among all 
 32.9   customers who choose to participate in the program.  
 32.10  Implementation of these rate options may reflect a reasonable 
 32.11  amount of lead time necessary to arrange acquisition of the 
 32.12  energy.  
 32.13     (d) If a utility is not able to arrange an adequate supply 
 32.14  of renewable or high-efficiency energy to meet its customers' 
 32.15  demand under this section, the utility must file a report with 
 32.16  the commission detailing its efforts and reasons for its failure.
 32.17     (e) The commission, by order, may establish a program for 
 32.18  tradeable credits for renewable energy under this section. 
 32.19     Sec. 3.  Minnesota Statutes 2000, section 216B.241, 
 32.20  subdivision 1, is amended to read: 
 32.21     Subdivision 1.  [DEFINITIONS.] For purposes of this section 
 32.22  and section sections 216B.16, subdivision 6b, and 216B.2411, the 
 32.23  terms defined in this subdivision have the meanings given them.  
 32.24     (a) "Commission" means the public utilities commission. 
 32.25     (b) "Commissioner" means the commissioner of public service 
 32.26  commerce. 
 32.27     (c) "Customer facility" means all buildings, structures, 
 32.28  equipment, and installations at a single site. 
 32.29     (d) "Department" means the department of public 
 32.30  service commerce. 
 32.31     (e) "Energy conservation improvement" means the purchase or 
 32.32  installation of a device, method, material, or project that: 
 32.33     (1) reduces consumption of or increases efficiency in the 
 32.34  use of electricity or natural gas, including but not limited to 
 32.35  insulation and ventilation, storm or thermal doors or windows, 
 32.36  caulking and weatherstripping, furnace efficiency modifications, 
 33.1   thermostat or lighting controls, awnings, or systems to turn off 
 33.2   or vary the delivery of energy; 
 33.3      (2) either (i) creates, converts, or actively uses energy 
 33.4   from renewable sources such as solar, wind, and biomass, or (ii) 
 33.5   recovers energy for reuse, from air or water or other similar 
 33.6   material, provided that the device or method conforms with 
 33.7   national or state performance and quality standards whenever 
 33.8   applicable; 
 33.9      (3) seeks to provide energy savings through reclamation or 
 33.10  recycling and that is used as part of the infrastructure of an 
 33.11  electric generation, transmission, or distribution system within 
 33.12  the state or a natural gas distribution system within the state; 
 33.13  or 
 33.14     (4) provides research or development of new means of 
 33.15  increasing energy efficiency or conserving energy or research or 
 33.16  development of improvement of existing means of increasing 
 33.17  energy efficiency or conserving energy. 
 33.18     For a public utility, municipal utility, or cooperative 
 33.19  electric association that elects to be governed by section 
 33.20  216B.2411, the difference between the amount required to be 
 33.21  spent under that section and the amount that the utility would 
 33.22  have spent under this section may be used (i) for purposes of 
 33.23  making grants for the development of renewable energy 
 33.24  facilities, such as those utilizing agricultural wastes as 
 33.25  biomass fuel and methane digester facilities associated with 
 33.26  livestock feedlots for the production of energy, and requiring 
 33.27  the grants, to the extent feasible, to be coordinated with loans 
 33.28  under the shared savings loan program established in section 
 33.29  17.115, and (ii) for the purchase or installation of a device, 
 33.30  method, or project that increases a customer's ability to 
 33.31  control the amount and scheduling of energy purchased from a 
 33.32  utility, resulting in an overall decrease in energy consumption, 
 33.33  through the innovative installation of high-efficiency on-site 
 33.34  generation such as fuel cells or microturbines in combination 
 33.35  with other conservation initiatives, or through other 
 33.36  technologies to allow customers to manage their own load. 
 34.1      (f) "Investments and expenses of a public utility" includes 
 34.2   the investments and expenses incurred by a public utility in 
 34.3   connection with an energy conservation improvement, including 
 34.4   but not limited to:  
 34.5      (1) the differential in interest cost between the market 
 34.6   rate and the rate charged on a no-interest or below-market 
 34.7   interest loan made by a public utility to a customer for the 
 34.8   purchase or installation of an energy conservation improvement; 
 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 such 
 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 20,000 10,000 kilowatts, 
 34.16  measured in the same way as the utility that serves the customer 
 34.17  facility measures electrical demand for billing purposes, and 
 34.18  for which electric services are provided at retail on a single 
 34.19  bill by a utility operating in the state. 
 34.20     Sec. 4.  Minnesota Statutes 2000, section 216B.241, 
 34.21  subdivision 1a, is amended to read: 
 34.22     Subd. 1a.  [INVESTMENT, EXPENDITURE, AND CONTRIBUTION; 
 34.23  PUBLIC UTILITY.] (a) For purposes of this subdivision and 
 34.24  subdivision 2, "public utility" has the meaning given it in 
 34.25  section 216B.02, subdivision 4.  Each public utility shall spend 
 34.26  and invest for energy conservation improvements under this 
 34.27  subdivision and subdivision 2 the following amounts: 
 34.28     (1) for a utility that furnishes gas service, 0.5 percent 
 34.29  of its gross operating revenues from service provided in the 
 34.30  state; 
 34.31     (2) for a utility that furnishes electric service, 1.5 
 34.32  percent of its gross operating revenues from service provided in 
 34.33  the state; and 
 34.34     (3) for a utility that furnishes electric service and that 
 34.35  operates a nuclear-powered electric generating plant within the 
 34.36  state, two percent of its gross operating revenues from service 
 35.1   provided in the state. 
 35.2   For purposes of this paragraph (a), "gross operating revenues" 
 35.3   do not include revenues from large electric customer facilities 
 35.4   exempted by the commissioner of the department of public service 
 35.5   pursuant to paragraph (b). 
 35.6      (b) The owner of a large electric customer facility may 
 35.7   petition the commissioner of the department of public 
 35.8   service commission to exempt both electric and gas utilities 
 35.9   serving the large energy customer facility from the investment 
 35.10  and expenditure requirements of paragraph (a) with respect to 
 35.11  retail revenues attributable to the facility.  At a minimum, the 
 35.12  petition must be supported by evidence relating to international 
 35.13  or domestic competitive or economic pressures on the customer 
 35.14  and a showing by the customer of reasonable efforts to identify, 
 35.15  evaluate, and implement cost-effective conservation improvements 
 35.16  at the facility.  The commission may grant the petition, 
 35.17  exempting both electric and gas utilities serving the large 
 35.18  energy customer facility from the investment and expenditure 
 35.19  requirements of paragraph (a) with respect to any percent of the 
 35.20  retail revenues attributable to the facility the commission 
 35.21  deems reasonable, upon a showing by the customer that it has 
 35.22  implemented all energy conservation improvements with a 
 35.23  seven-year payback or less, verified by a registered engineer or 
 35.24  other individual as authorized by the commission.  If a petition 
 35.25  is filed on or before October 1 of any year, the order of the 
 35.26  commissioner commission to exempt revenues attributable to the 
 35.27  facility can be effective no earlier than January 1 of the 
 35.28  following year.  The commissioner commission shall not grant an 
 35.29  exemption if the commissioner commission determines that 
 35.30  granting the exemption is contrary to the public interest.  
 35.31  The commissioner commission may, after investigation, rescind 
 35.32  any exemption granted under this paragraph upon a determination 
 35.33  that cost-effective energy conservation improvements are 
 35.34  available at the large electric customer facility.  For the 
 35.35  purposes of this paragraph, "cost-effective" means that the 
 35.36  projected total cost of the energy conservation improvement at 
 36.1   the large electric customer facility is less than the projected 
 36.2   present value of the energy and demand savings resulting from 
 36.3   the energy conservation improvement.  For the purposes of 
 36.4   investigations by the commissioner commission under this 
 36.5   paragraph, the owner of any large electric customer facility 
 36.6   shall, upon request, provide the commissioner commission with 
 36.7   updated information comparable to that originally supplied in or 
 36.8   with the owner's original petition under this paragraph. 
 36.9      (c) The commissioner may require investments or spending 
 36.10  greater than the amounts required under this subdivision for a 
 36.11  public utility whose most recent advance forecast required under 
 36.12  section 216B.2422 or 216C.17 projects a peak demand deficit of 
 36.13  100 megawatts or greater within five years under mid-range 
 36.14  forecast assumptions.  
 36.15     (d) A public utility or owner of a large electric customer 
 36.16  facility may appeal a decision of the commissioner under 
 36.17  paragraph (b) or (c) to the commission under subdivision 2.  In 
 36.18  reviewing a decision of the commissioner under paragraph (b) or 
 36.19  (c), the commission shall rescind the decision if it finds that 
 36.20  the required investments or spending will: 
 36.21     (1) not result in cost-effective energy conservation 
 36.22  improvements; or 
 36.23     (2) otherwise decision is not be in the public interest. 
 36.24     (e) Each utility shall determine what portion of the amount 
 36.25  it sets aside for conservation improvement will be used for 
 36.26  conservation improvements under subdivision 2 and what portion 
 36.27  it will contribute to the energy and conservation account 
 36.28  established in subdivision 2a.  A public utility may propose to 
 36.29  the commissioner to designate that all or a portion of funds 
 36.30  contributed to the account established in subdivision 2a be used 
 36.31  for research and development projects.  Contributions must be 
 36.32  remitted to the commissioner of public service by February 1 of 
 36.33  each year.  Nothing in this subdivision prohibits a public 
 36.34  utility from spending or investing for energy conservation 
 36.35  improvement more than required in this subdivision. 
 36.36     Sec. 5.  Minnesota Statutes 2000, section 216B.241, 
 37.1   subdivision 1b, is amended to read: 
 37.2      Subd. 1b.  [CONSERVATION IMPROVEMENT BY COOPERATIVE 
 37.3   ASSOCIATION OR MUNICIPALITY.] (a) This subdivision applies to: 
 37.4      (1) a cooperative electric association that generates and 
 37.5   transmits electricity to associations that provide electricity 
 37.6   at retail including a cooperative electric association not 
 37.7   located in this state that serves associations or others in the 
 37.8   state; 
 37.9      (2) a municipality that provides electric service to retail 
 37.10  customers; and 
 37.11     (3) a municipality with gross operating revenues in excess 
 37.12  of $5,000,000 from sales of natural gas to retail customers.  
 37.13     (b) Each cooperative electric association and municipality 
 37.14  subject to this subdivision shall spend and invest for energy 
 37.15  conservation improvements under this subdivision the following 
 37.16  amounts: 
 37.17     (1) for a municipality, 0.5 percent of its gross operating 
 37.18  revenues from the sale of gas and one percent of its gross 
 37.19  operating revenues from the sale of electricity not purchased 
 37.20  from a public utility governed by subdivision 1a or a 
 37.21  cooperative electric association governed by this subdivision, 
 37.22  excluding gross operating revenues from electric and gas service 
 37.23  provided in the state to large electric customer facilities; and 
 37.24     (2) for a cooperative electric association, 1.5 percent of 
 37.25  its gross operating revenues from service provided in the state, 
 37.26  excluding gross operating revenues from service provided in the 
 37.27  state to large electric customer facilities indirectly through a 
 37.28  distribution cooperative electric association. 
 37.29     (c) Each municipality and cooperative association subject 
 37.30  to this subdivision shall identify and implement energy 
 37.31  conservation improvement spending and investments that are 
 37.32  appropriate for the municipality or association, except that a 
 37.33  municipality or association may not spend or invest for energy 
 37.34  conservation improvements that directly benefit a large electric 
 37.35  customer facility.  Each municipality and cooperative electric 
 37.36  association subject to this subdivision may spend and invest 
 38.1   annually up to 15 percent of the total amount required to be 
 38.2   spent and invested on energy conservation improvements under 
 38.3   this subdivision on research and development projects that meet 
 38.4   the definition of energy conservation improvement in subdivision 
 38.5   1 and that are funded directly by the municipality or 
 38.6   cooperative electric association.  Load management may be used 
 38.7   to meet the requirements of this subdivision if it reduces the 
 38.8   demand for or increases the efficiency of electric 
 38.9   services.  However, each dollar spent on load management 
 38.10  initiatives only counts for (1) $0.65 in 2003, and (2) $0.25 in 
 38.11  2004 and thereafter toward the utility's or association's 
 38.12  conservation spending obligation under this section or section 
 38.13  216B.2411.  A generation and transmission cooperative electric 
 38.14  association may include as spending and investment required 
 38.15  under this subdivision conservation improvement spending and 
 38.16  investment by cooperative electric associations that provide 
 38.17  electric service at retail to consumers and that are served by 
 38.18  the generation and transmission association. 
 38.19     (d) By February 1 of each year, each municipality or 
 38.20  cooperative shall report to the commissioner its energy 
 38.21  conservation improvement spending and investments with a brief 
 38.22  analysis of effectiveness in reducing consumption of electricity 
 38.23  or gas.  The commissioner shall review each report and make 
 38.24  recommendations, where appropriate, to the municipality or 
 38.25  association to increase the effectiveness of conservation 
 38.26  improvement activities.  The commissioner shall also review each 
 38.27  report for whether a portion of the money spent on residential 
 38.28  conservation improvement programs is devoted to programs that 
 38.29  directly address the needs of renters and low-income persons 
 38.30  unless an insufficient number of appropriate programs are 
 38.31  available.  For the purposes of this subdivision and subdivision 
 38.32  2, "low-income" means an income of less than 185 percent of the 
 38.33  federal poverty level. 
 38.34     (e) As part of its spending for conservation improvement, a 
 38.35  municipality or association may contribute to the energy and 
 38.36  conservation account.  A municipality or association may propose 
 39.1   to the commissioner to designate that all or a portion of funds 
 39.2   contributed to the account be used for research and development 
 39.3   projects.  Any amount contributed must be remitted to the 
 39.4   commissioner of public service by February 1 of each year.  
 39.5      Sec. 6.  Minnesota Statutes 2000, section 216B.241, 
 39.6   subdivision 2, is amended to read: 
 39.7      Subd. 2.  [PROGRAMS.] (a) The commissioner commission may 
 39.8   by rule or order require public utilities to make investments 
 39.9   and expenditures in energy conservation improvements, explicitly 
 39.10  setting forth the interest rates, prices, and terms under which 
 39.11  the improvements must be offered to the customers.  The required 
 39.12  programs must cover a two-year period.  The commissioner shall 
 39.13  require at least one public utility to establish a pilot program 
 39.14  to make investments in and expenditures for energy from 
 39.15  renewable resources such as solar, wind, or biomass and shall 
 39.16  give special consideration and encouragement to programs that 
 39.17  bring about significant net savings through the use of 
 39.18  energy-efficient lighting.  The commissioner commission shall 
 39.19  evaluate the program on the basis of cost-effectiveness and the 
 39.20  reliability of technologies employed.  The rules of the 
 39.21  department under this section must provide to the extent 
 39.22  practicable for a free choice, by consumers participating in the 
 39.23  program, of the device, method, material, or project 
 39.24  constituting the energy conservation improvement and for a free 
 39.25  choice of the seller, installer, or contractor of the energy 
 39.26  conservation improvement, provided that the device, method, 
 39.27  material, or project seller, installer, or contractor is duly 
 39.28  licensed, certified, approved, or qualified, including under the 
 39.29  residential conservation services program, where applicable.  
 39.30     (b) The commissioner commission may require a utility to 
 39.31  make an energy conservation improvement investment or 
 39.32  expenditure whenever the commissioner commission finds that the 
 39.33  improvement will result in energy savings at a total cost to the 
 39.34  utility less than the cost to the utility to produce or purchase 
 39.35  an equivalent amount of new supply of energy.  The commissioner 
 39.36  shall nevertheless ensure that every public utility operate one 
 40.1   or more programs under periodic review by the department.  Load 
 40.2   management may be used to meet the requirements for energy 
 40.3   conservation improvements under this section if it results in a 
 40.4   demonstrable reduction in consumption of energy.  Each public 
 40.5   utility subject to subdivision 1a may spend and invest annually 
 40.6   up to 15 percent of the total amount required to be spent and 
 40.7   invested on energy conservation improvements under this section 
 40.8   by the utility on research and development projects that meet 
 40.9   the definition of energy conservation improvement in subdivision 
 40.10  1 and that are funded directly by the public utility.  A public 
 40.11  utility may not spend for or invest in energy conservation 
 40.12  improvements that directly benefit a large electric customer 
 40.13  facility for which the commissioner commission has issued an 
 40.14  exemption pursuant to subdivision 1a, paragraph (b).  
 40.15  The commissioner commission shall consider and may require a 
 40.16  utility to undertake a program suggested by an outside source, 
 40.17  including a political subdivision or a nonprofit or community 
 40.18  organization. 
 40.19     (c) No utility may make an energy conservation improvement 
 40.20  under this section to a building envelope unless: 
 40.21     (1) it is the primary supplier of energy used for either 
 40.22  space heating or cooling in the building; 
 40.23     (2) the commissioner commission determines that special 
 40.24  circumstances, that would unduly restrict the availability of 
 40.25  conservation programs, warrant otherwise; or 
 40.26     (3) the utility has been awarded a contract under 
 40.27  subdivision 2a. 
 40.28     (d) The commissioner commission shall ensure that a portion 
 40.29  of the money spent on residential conservation improvement 
 40.30  programs is devoted to programs that directly address the needs 
 40.31  of renters and low-income persons unless an insufficient number 
 40.32  of appropriate programs are available. 
 40.33     (e) A utility, a political subdivision, or a nonprofit or 
 40.34  community organization that has suggested a program, the 
 40.35  attorney general acting on behalf of consumers and small 
 40.36  business interests, or a utility customer that has suggested a 
 41.1   program and is not represented by the attorney general under 
 41.2   section 8.33 may petition the commission to modify or revoke a 
 41.3   department decision under this section, and the commission may 
 41.4   do so if it determines that the program is not cost-effective, 
 41.5   does not adequately address the residential conservation 
 41.6   improvement needs of low-income persons, has a long-range 
 41.7   negative effect on one or more classes of customers, or is 
 41.8   otherwise not in the public interest.  The person petitioning 
 41.9   for commission review has the burden of proof.  The commission 
 41.10  shall reject a petition that, on its face, fails to make a 
 41.11  reasonable argument that a program is not in the public interest.
 41.12     Sec. 7.  Minnesota Statutes 2000, section 216B.241, 
 41.13  subdivision 2a, is amended to read: 
 41.14     Subd. 2a.  [ENERGY AND CONSERVATION ACCOUNT LOW-INCOME 
 41.15  PERSONS.] The commissioner must deposit money contributed under 
 41.16  subdivisions 1a and 1b in the energy and conservation account in 
 41.17  the general fund.  Money in the account is appropriated to the 
 41.18  department for programs designed to meet the energy conservation 
 41.19  needs of low-income persons and to make energy conservation 
 41.20  improvements in areas not adequately served under subdivision 2, 
 41.21  including research and development projects included in the 
 41.22  definition of energy conservation improvement in subdivision 1.  
 41.23  Interest on money in the account accrues to the account.  Using 
 41.24  information collected under section 216C.02, subdivision 1, 
 41.25  paragraph (b), the commissioner must, to the extent possible, 
 41.26  allocate enough money to programs for low-income persons to 
 41.27  assure that their needs are being adequately addressed.  The 
 41.28  commissioner must request the commissioner of finance to 
 41.29  transfer money from the account to the commissioner of children, 
 41.30  families, and learning for an energy conservation program for 
 41.31  low-income persons.  In establishing programs, the commissioner 
 41.32  must consult political subdivisions and nonprofit and community 
 41.33  organizations, especially organizations engaged in providing 
 41.34  energy and weatherization assistance to low-income persons.  At 
 41.35  least one program must address the need for energy conservation 
 41.36  improvements in areas in which a high percentage of residents 
 42.1   use fuel oil or propane to fuel their source of home heating.  
 42.2   The commissioner may contract with a political subdivision, a 
 42.3   nonprofit or community organization, a public utility, a 
 42.4   municipality, or a cooperative electric association to implement 
 42.5   its programs.  The commissioner may provide grants to any person 
 42.6   to conduct research and development projects in accordance with 
 42.7   this section. 
 42.8      Sec. 8.  Minnesota Statutes 2000, section 216B.241, is 
 42.9   amended by adding a subdivision to read: 
 42.10     Subd. 6.  [OVERVIEW; REVIEW AND AUDIT.] (a) For 
 42.11  conservation activities under section 216B.2411, each public 
 42.12  utility shall provide the commission with a prospective overview 
 42.13  of the utility's planned conservation activities and the 
 42.14  anticipated energy savings on a biennial basis, according to a 
 42.15  schedule established by the commission.  This overview shall 
 42.16  include a description of the types of activities, the consumer 
 42.17  sectors targeted by each, and the anticipated energy savings and 
 42.18  costs of each activity.  This overview shall also indicate, for 
 42.19  each type of activity, how much additional cost-effective 
 42.20  conservation is likely to be achieved in subsequent years.  In 
 42.21  addition, each public utility shall provide a report biennially 
 42.22  to the commission summarizing the public utility's actual 
 42.23  conservation activities over the previous two years, including, 
 42.24  for each activity, the utility's costs to the utility and to 
 42.25  participating customers, the utility's expected total energy 
 42.26  savings, the number of participating customers in each customer 
 42.27  class and consumer sector, and the activity's potential for 
 42.28  realizing additional cost-effective energy savings in the future.
 42.29     (b) Each public utility shall provide a report biennially 
 42.30  to the commission summarizing the public utility's conservation 
 42.31  activities and energy savings resulting from those activities 
 42.32  under either this section or section 216B.2411.  The public 
 42.33  utility shall include in the report the results of an 
 42.34  independent audit performed by the department or an auditor with 
 42.35  experience in the provision of energy conservation and energy 
 42.36  efficiency services approved by the commission.  The commission 
 43.1   shall issue a report comparing the overall effectiveness of the 
 43.2   conservation programs in overall cost, success in reducing 
 43.3   overall energy use, and energy saved per dollar spent. 
 43.4      (c) The audit provided under paragraph (b) shall evaluate 
 43.5   whether the public utility has implemented cost-effective energy 
 43.6   conservation programs.  In making this evaluation, the audit 
 43.7   shall consider whether the public utility's programs (1) fairly 
 43.8   address each of the utility's consumer classes and market 
 43.9   sectors, (2) use accurate data in calculating costs and energy 
 43.10  savings, and (3) indicate an adequate commitment to implementing 
 43.11  cost-effective conservation programs.  Up to five percent of a 
 43.12  utility's conservation spending obligation under this section or 
 43.13  section 216B.2411 may be used for program pre-evaluation, 
 43.14  research and testing, monitoring, and program evaluation. 
 43.15     (d) Following two or more negative evaluations under 
 43.16  paragraph (b), the commission may determine that a public 
 43.17  utility is not implementing adequate energy conservation 
 43.18  programs under section 216B.2411.  In that event, the commission 
 43.19  may order the utility or association to commit an appropriate 
 43.20  amount of its conservation spending obligations under those 
 43.21  sections to providing conservation programs under section 
 43.22  216B.241. 
 43.23     Sec. 9.  Minnesota Statutes 2000, section 216B.241, is 
 43.24  amended by adding a subdivision to read: 
 43.25     Subd. 7.  [ADDITIONAL CONSERVATION SPENDING.] (a) Nothing 
 43.26  in this section or section 216B.2411 prohibits any energy 
 43.27  utility from spending or investing more for energy conservation 
 43.28  improvements than is required in those sections. 
 43.29     (b) The commission may require a public utility to invest 
 43.30  or spend more than is required under this section or section 
 43.31  216B.2411 if the commission finds that additional investments 
 43.32  would be cost effective, and the utility's most recent forecast 
 43.33  projects a significant peak demand deficit. 
 43.34     Sec. 10.  [216B.2411] [CONSERVATION INVESTMENT PROGRAM.] 
 43.35     Subdivision 1.  [DEFINITIONS.] The definitions in section 
 43.36  216B.241 apply to this section. 
 44.1      Subd. 2.  [INVESTMENTS.] (a) A public utility, 
 44.2   municipality, or cooperative electric association may elect to 
 44.3   be governed by this section rather than section 216B.241, by 
 44.4   notifying the commission of its election.  However, section 
 44.5   216B.241, subdivisions 1a, paragraph (b); 1b, paragraph (c); and 
 44.6   2b, apply to conservation investments made under this section. 
 44.7      (b) Each entity that elects to be governed by this section 
 44.8   shall spend and invest for energy conservation improvements the 
 44.9   following amounts: 
 44.10     (1) for a public utility that furnishes gas service, 0.75 
 44.11  percent of the utility's annual average gross operating revenues 
 44.12  over the previous five years from service provided in this 
 44.13  state; 
 44.14     (2) for a cooperative electric association that provides 
 44.15  electricity at retail or a public utility that furnishes 
 44.16  electric service, two percent of the utility's or association's 
 44.17  annual average gross operating revenues over the previous five 
 44.18  years from service provided in this state; 
 44.19     (3) for a utility that furnishes electric service and that 
 44.20  operates a nuclear-powered electric generating plant within the 
 44.21  state, three percent of the utility's annual average gross 
 44.22  operating revenues over the previous five years from service 
 44.23  provided in this state; and 
 44.24     (4) for a municipality, 0.75 percent of the utility's 
 44.25  annual average gross operating revenues over the previous five 
 44.26  years from the sale of gas and 1.5 percent of the utility's 
 44.27  annual average gross operating revenues over the previous five 
 44.28  years from the sale of electricity not purchased from a public 
 44.29  utility or a cooperative electric association governed by this 
 44.30  subdivision over its five-year conservation spending average. 
 44.31  For purposes of this paragraph, "gross operating revenues" do 
 44.32  not include revenues from large electric customer facilities 
 44.33  exempted by the commissioner pursuant to section 216B.241, 
 44.34  subdivision 1a, paragraph (b).  Entities electing to be governed 
 44.35  by this section shall comply with section 216B.241, subdivision 
 44.36  6. 
 45.1      Sec. 11.  [216B.401] [UTILITY JOINT VENTURES.] 
 45.2      Subdivision 1.  [AUTHORIZATION.] Public utilities, 
 45.3   cooperative electric associations, and municipal utilities may 
 45.4   enter into joint ventures with one another for providing utility 
 45.5   services within the boundaries of each member utility's 
 45.6   exclusive electric service territory, as shown on the map of 
 45.7   service territories maintained by the department of commerce.  
 45.8   The terms and conditions of each proposed joint venture are 
 45.9   subject to ratification by the governing body of each member 
 45.10  municipal utility and cooperative association and, if a public 
 45.11  utility is a member of the proposed joint venture, the 
 45.12  commission.  A joint venture may include the formation of a 
 45.13  corporate entity with an administrative and governance structure 
 45.14  independent of any of the member utilities.  A corporate entity 
 45.15  formed under this section is subject to all laws and rules 
 45.16  applicable to the respective members of the joint venture. 
 45.17     Subd. 2.  [POWERS.] (a) The joint venture formed under this 
 45.18  section, if any, has the powers, privileges, responsibilities, 
 45.19  and duties of the separate utilities entering into the joint 
 45.20  venture as the joint venture agreement may provide; except that, 
 45.21  upon formation of the joint venture, neither the joint venture 
 45.22  nor any member municipal utility has the power of eminent domain 
 45.23  or the authority under section 216B.44 to enlarge the service 
 45.24  territory served by the joint venture. 
 45.25     (b) These powers include, but are not limited to, the 
 45.26  authority to: 
 45.27     (1) finance, own, construct, and operate facilities 
 45.28  necessary for providing electric power to wholesale or retail 
 45.29  customers, including generation, transmission, and distribution 
 45.30  facilities; 
 45.31     (2) combine service territories, in whole or in part, upon 
 45.32  notice and hearing to do so with the public utilities 
 45.33  commission; 
 45.34     (3) serve customers in the two utilities' service 
 45.35  territories or in the combined service territory; 
 45.36     (4) combine, share, or employ administrative, managerial, 
 46.1   operational, or other staff if combining or sharing will not 
 46.2   degrade safety, reliability, or customer service standards; 
 46.3      (5) provide for joint administrative functions, such as 
 46.4   meter reading and billing; 
 46.5      (6) purchase or sell power at wholesale for resale to 
 46.6   customers; 
 46.7      (7) as required by law or rule, provide energy conservation 
 46.8   programs, other utility programs, public interest programs such 
 46.9   as cold weather shutoff protection, and energy conservation 
 46.10  spending programs; and 
 46.11     (8) participate as the parties deem necessary in providing 
 46.12  wholesale electric power with other municipal utilities, rural 
 46.13  electric cooperative utilities, investor-owned utilities, or 
 46.14  other entities, public or private. 
 46.15     Sec. 12.  Minnesota Statutes 2000, section 216B.42, 
 46.16  subdivision 1, is amended to read: 
 46.17     Subdivision 1.  [LARGE CUSTOMER OUTSIDE MUNICIPALITY 
 46.18  ELECTION.] (a) Notwithstanding the establishment of assigned 
 46.19  service areas for electric utilities provided for in section 
 46.20  216B.39, customers:  (i) located outside municipalities and who 
 46.21  require electric service with a connected load of 2,000 
 46.22  kilowatts or more shall not be obligated to take electric 
 46.23  service from the electric utility having the assigned service 
 46.24  area where the customer is located; or (ii) who require electric 
 46.25  service with a connected load of 5,000 kilowatts or more shall 
 46.26  not be obligated to take power supply service from the electric 
 46.27  utility having the assigned service area where the customer is 
 46.28  located, if, after notice and hearing, the commission, for a 
 46.29  public utility, or the governing body of a municipal utility or 
 46.30  cooperative electric association, so determines after 
 46.31  consideration of following factors: 
 46.32     (1) the electric service requirements of the load to be 
 46.33  served; 
 46.34     (2) the availability of an adequate power supply; 
 46.35     (3) the development or improvement of the electric system 
 46.36  of the utility seeking to provide the electric service, 
 47.1   including the economic factors relating thereto; 
 47.2      (4) the proximity of adequate facilities from which 
 47.3   electric service of the type required may be delivered; 
 47.4      (5) the preference of the customer; 
 47.5      (6) any and all pertinent factors affecting the ability of 
 47.6   the utility to furnish adequate electric service to fulfill 
 47.7   customers' requirements.  
 47.8      (b) The commission or governing body may not grant a 
 47.9   petition under this section unless it makes a specific finding 
 47.10  that there is clear and convincing evidence that doing so would 
 47.11  not increase costs for, or otherwise harm, any of the customers 
 47.12  of the utility currently serving the customer or, in the case of 
 47.13  a municipal power agency or a generation and transmission 
 47.14  cooperative electric association, any of the customers of a 
 47.15  member utility.  If the commission or governing body grants a 
 47.16  petition under paragraph (a), item (ii), it shall impose all 
 47.17  terms and conditions on the approval that are necessary to 
 47.18  protect consumers, utilities, and utility systems.  For the 
 47.19  purposes of this section, "power supply services" means the 
 47.20  provision of electric power supply to an end-use customer.  
 47.21  Power supply services includes a service relating to the usage, 
 47.22  purchase, or sale of electric capacity and energy, but does not 
 47.23  include the operation of generation facilities, or distribution 
 47.24  or transmission services. 
 47.25     Sec. 13.  [CONSERVATION IMPROVEMENT PLAN; EVALUATION OF 
 47.26  COOPERATIVE AND MUNICIPAL PROGRAMS.] 
 47.27     (a) Cooperative electric association and municipal 
 47.28  utilities shall evaluate their energy and capacity conservation 
 47.29  programs, develop plans for future programs, and report their 
 47.30  findings and plans to the chairs of the house of representatives 
 47.31  and senate committees with jurisdiction over energy issues by 
 47.32  February 15, 2002.  The evaluation shall address: 
 47.33     (1) whether the utility or association has implemented and 
 47.34  is implementing cost-effective energy conservation programs; 
 47.35     (2) the availability of basic conservation services and 
 47.36  programs to customers; 
 48.1      (3) methodologies that best quantify energy savings, cost 
 48.2   effectiveness, and the potential for cost-effective conservation 
 48.3   improvements; 
 48.4      (4) the value of local administration of conservation 
 48.5   programs in meeting local and statewide needs; 
 48.6      (5) the effect on customer bills; 
 48.7      (6) the role of capacity conservation in meeting utility 
 48.8   planning needs and state energy goals; 
 48.9      (7) the ability of energy conservation programs to avoid 
 48.10  the need for construction of generation facilities and 
 48.11  transmission lines; 
 48.12     (8) whether the utility's or association's programs address 
 48.13  all of the following consumer market sectors:  farm, 
 48.14  residential, commercial, and industrial; and 
 48.15     (9) whether the utility's or association's programs use 
 48.16  accurate and auditable data in calculating costs and energy 
 48.17  savings. 
 48.18     (b) The evaluation shall develop program and performance 
 48.19  goals that recognize customer class, utility service area 
 48.20  demographics, cost of program delivery, regional economic 
 48.21  indicators, and utility load shape.  The cost of the evaluation 
 48.22  may be deducted from the utility's or association's conservation 
 48.23  spending obligation under section 216B.241 or 216B.2411. 
 48.24                             ARTICLE 4
 48.25              INTERCONNECTION OF DISTRIBUTED RESOURCES
 48.26     Section 1.  [216B.68] [DEFINITIONS.] 
 48.27     Subdivision 1.  [SCOPE.] The words and terms used in 
 48.28  sections 216B.68 to 216B.75 have the meanings given them in this 
 48.29  section. 
 48.30     Subd. 2.  [APPLICATION FOR INTERCONNECTION AND PARALLEL 
 48.31  OPERATION.] "Application for interconnection and parallel 
 48.32  operation" with the utility system or application means a 
 48.33  standard form of application developed by the commissioner and 
 48.34  approved by the commission. 
 48.35     Subd. 3.  [COMPANY.] "Company" means an electric utility 
 48.36  operating a distribution system. 
 49.1      Subd. 4.  [ELECTRIC UTILITY.] "Electric utility" means all 
 49.2   electric utilities that own and operate equipment in the state 
 49.3   for furnishing electric service at retail. 
 49.4      Subd. 5.  [CUSTOMER.] "Customer" means any individual 
 49.5   person or entity interconnected to the company's utility system 
 49.6   for the purpose of receiving or exporting electric power from or 
 49.7   to the company's utility system. 
 49.8      Subd. 6.  [DISTRIBUTED GENERATION OR ON-SITE DISTRIBUTED 
 49.9   GENERATION.] "Distributed generation" or "on-site distributed 
 49.10  generation" means an electrical generating facility located at a 
 49.11  customer's point of delivery or point of common coupling of 20 
 49.12  megawatts or less and connected at a voltage less than or equal 
 49.13  to 60 kilovolts that may be connected in parallel operation to 
 49.14  the utility system. 
 49.15     Subd. 7.  [FACILITY.] "Facility" means an electrical 
 49.16  generating installation consisting of one or more on-site 
 49.17  distributed generation units.  The total capacity of a 
 49.18  facility's individual on-site distributed generation units may 
 49.19  exceed 20 megawatts; however, no more than 20 megawatts of a 
 49.20  facility's capacity will be interconnected at any point in time 
 49.21  at the point of common coupling under this section. 
 49.22     Subd. 8.  [INTERCONNECTION.] "Interconnection" means the 
 49.23  physical connection of distributed generation to the utility 
 49.24  system in accordance with the requirements of this section so 
 49.25  that parallel operation can occur. 
 49.26     Subd. 9.  [INTERCONNECTION AGREEMENT.] "Interconnection 
 49.27  agreement" means the standard form of agreement, developed and 
 49.28  approved by the commission.  The interconnection agreement sets 
 49.29  forth the contractual conditions under which a company and a 
 49.30  customer agree that one or more facilities may be interconnected 
 49.31  with the company's utility system. 
 49.32     Subd. 10.  [INVERTER-BASED PROTECTIVE 
 49.33  FUNCTION.] "Inverter-based protective function" means a function 
 49.34  of an inverter system, carried out using hardware and software, 
 49.35  that is designed to prevent unsafe operating conditions from 
 49.36  occurring before, during, and after the interconnection of an 
 50.1   inverter-based static power converter unit with a utility 
 50.2   system.  For purposes of this definition, unsafe operating 
 50.3   conditions are conditions that, if left uncorrected, would 
 50.4   result in harm to personnel, damage to equipment, unacceptable 
 50.5   system instability, or operation outside legally established 
 50.6   parameters affecting the quality of service to other customers 
 50.7   connected to the utility system. 
 50.8      Subd. 11.  [NETWORK SERVICE.] "Network service" means two 
 50.9   or more utility primary distribution feeder sources electrically 
 50.10  tied together on the secondary side, which is the low-voltage 
 50.11  side, to form one power source for one or more customers.  The 
 50.12  service is designed to maintain service to the customers even 
 50.13  after the loss of one of these primary distribution feeder 
 50.14  sources. 
 50.15     Subd. 12.  [PARALLEL OPERATION.] "Parallel operation" means 
 50.16  the operation of on-site distributed generation by a customer 
 50.17  while the customer is connected to the company's utility system. 
 50.18     Subd. 13.  [POINT OF COMMON COUPLING.] "Point of common 
 50.19  coupling" means the point where the electrical conductors of the 
 50.20  company utility system are connected to the customer's 
 50.21  conductors and where any transfer of electric power between the 
 50.22  customer and the utility system takes place, such as switchgear 
 50.23  near the meter. 
 50.24     Subd. 14.  [PRECERTIFIED EQUIPMENT.] "Precertified 
 50.25  equipment" means a specific generating and protective equipment 
 50.26  system or systems that have been certified as meeting the 
 50.27  applicable parts of this section relating to safety and 
 50.28  reliability by an entity approved by the commission. 
 50.29     Subd. 15.  [PRE-INTERCONNECTION STUDY.] 
 50.30  "Pre-interconnection study" means a study or studies that may be 
 50.31  undertaken by a company in response to its receipt of a 
 50.32  completed application for interconnection and parallel operation 
 50.33  with the utility system.  Pre-interconnection studies may 
 50.34  include, but are not limited to, service studies, coordination 
 50.35  studies, and utility system impact studies. 
 50.36     Subd. 16.  [STABILIZED.] "Stabilized" means that, following 
 51.1   a disturbance, a company utility system has returned to the 
 51.2   normal range of voltage and frequency for a duration of two 
 51.3   minutes or a shorter time as mutually agreed to by the company 
 51.4   and customer. 
 51.5      Subd. 17.  [TARIFF OR TARIFF FOR INTERCONNECTION AND 
 51.6   PARALLEL OPERATION OF DISTRIBUTED GENERATION.] "Tariff" or 
 51.7   "Tariff for interconnection and parallel operation of 
 51.8   distributed generation" means the commission-developed and 
 51.9   commission-approved tariff for interconnection and parallel 
 51.10  operation of distributed generation, including the application 
 51.11  for interconnection and parallel operation of distributed 
 51.12  generation and pre-interconnection study fee schedule. 
 51.13     Subd. 18.  [UNIT.] "Unit" means a power generator. 
 51.14     Subd. 19.  [UTILITY SYSTEM.] "Utility system" means a 
 51.15  company's distribution system below 60 kilovolts to which the 
 51.16  generation equipment is interconnected. 
 51.17     Sec. 2.  [216B.69] [INTERCONNECTION OF ON-SITE DISTRIBUTED 
 51.18  GENERATION.] 
 51.19     Subdivision 1.  [PURPOSE.] The purpose of sections 216B.68 
 51.20  to 216B.75 is to state the terms and conditions that govern the 
 51.21  interconnection and parallel operation of on-site distributed 
 51.22  generation to provide cost savings and reliability benefits to 
 51.23  customers, to establish technical requirements that will promote 
 51.24  the safe and reliable parallel operation of on-site distributed 
 51.25  generation resources, to enhance both the reliability of 
 51.26  electric service and economic efficiency in the production and 
 51.27  consumption of electricity, and to promote the use of 
 51.28  distributed resources in order to provide electric system 
 51.29  benefits during periods of capacity constraints. 
 51.30     Subd. 2.  [OBLIGATION TO SERVE; TARIFF AND OTHER 
 51.31  FILINGS.] (a) No later than 270 days after the effective date of 
 51.32  this section, each electric utility shall file tariffs for 
 51.33  interconnection and parallel operation of distributed generation 
 51.34  in conformance with sections 216B.68 to 216B.75.  The electric 
 51.35  utility may file a new tariff or a modification of an existing 
 51.36  tariff.  These tariffs must ensure that backup power, 
 52.1   supplemental power, and maintenance power are available to all 
 52.2   customers and customer classes that desire this service.  Any 
 52.3   modifications of existing tariffs or offerings of new tariffs 
 52.4   relating to this section must be consistent with the 
 52.5   commission-approved form.  
 52.6      (b) Concurrent with the tariff filing in this section, each 
 52.7   utility shall submit: 
 52.8      (1) a schedule detailing the charges of interconnection 
 52.9   studies and all supporting cost data for the charges; 
 52.10     (2) a standard application for interconnection and parallel 
 52.11  operation of distributed generation; and 
 52.12     (3) the interconnection agreement approved by the 
 52.13  commission. 
 52.14     Sec. 3.  [216B.70] [DISCONNECTION AND RECONNECTION.] 
 52.15     Subdivision 1.  [WHEN DISCONNECTION ALLOWED.] A utility may 
 52.16  disconnect a distributed generation unit from the utility system 
 52.17  if: 
 52.18     (1) the interconnection agreement with a customer expires 
 52.19  or terminates, in accordance with the terms of the agreement; 
 52.20     (2) the facility is not in compliance with the technical 
 52.21  requirements specified by the commissioner; 
 52.22     (3) continued interconnection will endanger persons or 
 52.23  property; or 
 52.24     (4) written notice is provided at least seven business days 
 52.25  prior to a service interruption for routine maintenance, 
 52.26  repairs, and utility system modifications. 
 52.27     Subd. 2.  [INCREMENTAL DEMAND CHARGES.] During the term of 
 52.28  an interconnection agreement, a utility may require that a 
 52.29  customer disconnect its distributed generation unit or take it 
 52.30  off-line as a result of utility system conditions.  The company 
 52.31  may not assess the customer incremental demand charges arising 
 52.32  from disconnecting the distributed generator as directed by the 
 52.33  company during these periods. 
 52.34     Sec. 4.  [216B.71] [PRE-INTERCONNECTION STUDIES FOR 
 52.35  NONNETWORK INTERCONNECTION OF DISTRIBUTED GENERATION.] 
 52.36     Subdivision 1.  [STUDIES.] A utility may conduct a service 
 53.1   study, coordination study, or utility system impact study prior 
 53.2   to interconnection of a distributed generation facility.  When a 
 53.3   study is deemed necessary, the scope of the study must be based 
 53.4   on the characteristics of the particular distributed generation 
 53.5   facility to be interconnected and the utility's system at the 
 53.6   specific proposed location.  By agreement between the utility 
 53.7   and its customer, a study related to interconnection of 
 53.8   distributed generation on the customer's premises may be 
 53.9   conducted by a qualified third party. 
 53.10     Subd. 2.  [CUSTOMER FEE.] (a) A utility may not charge a 
 53.11  customer a fee to conduct a pre-interconnection study for 
 53.12  precertified distributed generation units up to 500 kilowatts 
 53.13  that export not more than 15 percent of the total load on a 
 53.14  single radial feeder and contribute not more than 25 percent of 
 53.15  the maximum potential short circuit current on a single radial 
 53.16  feeder. 
 53.17     (b) Prior to the interconnection of a distributed 
 53.18  generation facility not described in paragraph (a), a utility 
 53.19  may charge a customer a fee to offset its costs incurred in the 
 53.20  conduct of a pre-interconnection study.  
 53.21     Subd. 3.  [WHEN UTILITY CONDUCTS STUDY.] When a utility 
 53.22  conducts an interconnection study, paragraphs (a) to (d) apply: 
 53.23     (a) The conduct of the pre-interconnection study may not 
 53.24  take more than four weeks. 
 53.25     (b) A utility shall prepare written reports of the study 
 53.26  findings and make them available to the customer. 
 53.27     (c) The study must consider both the costs incurred and the 
 53.28  benefits realized as a result of the interconnection of 
 53.29  distributed generation to the company's utility system. 
 53.30     (d) The utility shall provide the customer with an estimate 
 53.31  of the study cost before the utility initiates the study. 
 53.32     Sec. 5.  [216B.72] [PRE-INTERCONNECTION STUDIES FOR NETWORK 
 53.33  INTERCONNECTION OF DISTRIBUTED GENERATION.] 
 53.34     Subdivision 1.  [NOTICE AND FEES.] (a) Prior to charging a 
 53.35  pre-interconnection study fee for a network interconnection of 
 53.36  distributed generation, a utility shall first advise the 
 54.1   customer of the potential problems associated with 
 54.2   interconnection of distributed generation with its network 
 54.3   system.  
 54.4      (b) For potential interconnections to network systems, a 
 54.5   pre-interconnection study fee may not be assessed for a facility 
 54.6   with inverter systems under 20 kilowatts.  For all other 
 54.7   facilities, the utility may charge the customer a fee to offset 
 54.8   its costs incurred in the conduct of the pre-interconnection 
 54.9   study.  
 54.10     Subd. 2.  [REQUIREMENTS WHEN UTILITY CONDUCTS STUDY.] When 
 54.11  a utility conducts an interconnection study, paragraphs (a) to 
 54.12  (d) apply: 
 54.13     (a) The conduct of a pre-interconnection study may not take 
 54.14  more than four weeks. 
 54.15     (b) A utility shall prepare written reports of the study 
 54.16  findings and make them available to the customer. 
 54.17     (c) The study must consider both the costs incurred and the 
 54.18  benefits realized as a result of the interconnection of 
 54.19  distributed generation to the utility's system. 
 54.20     (d) The utility shall provide the customer with an estimate 
 54.21  of the study cost before the utility initiates the study. 
 54.22     Sec. 6.  [216B.73] [EQUIPMENT PRECERTIFICATION.] (a) The 
 54.23  commission may approve one or more entities that shall 
 54.24  precertify equipment as described under this section. 
 54.25     (b) Testing organizations or facilities capable of 
 54.26  analyzing the function, control, and protective systems of 
 54.27  distributed generation units may request to be certified as 
 54.28  testing organizations. 
 54.29     (c) Distributed generation units that are certified to be 
 54.30  in compliance by an approved testing facility or organization 
 54.31  must be installed on a company utility system in accordance with 
 54.32  an approved interconnection control and protection scheme 
 54.33  without further review of their design by the utility. 
 54.34     Sec. 7.  [216B.74] [TIME FOR PROCESSING APPLICATIONS FOR 
 54.35  INTERCONNECTION.] 
 54.36     (a) The interconnection of distributed generation to the 
 55.1   utility system must take place within the schedules described in 
 55.2   paragraphs (b) to (f): 
 55.3      (b) For a facility with precertified equipment, 
 55.4   interconnection must take place within four weeks of the 
 55.5   utility's receipt of a completed interconnection application. 
 55.6      (c) For facilities without precertified equipment, 
 55.7   connection must take place within six weeks of the utility's 
 55.8   receipt of a completed application. 
 55.9      (d) If interconnection of a particular facility will 
 55.10  require substantial capital upgrades to the utility system, the 
 55.11  company shall provide the customer an estimate of the schedule 
 55.12  and the customer's cost for the upgrade.  If the customer 
 55.13  desires to proceed with the upgrade, the customer and the 
 55.14  company shall enter into a contract for the completion of the 
 55.15  upgrade.  The interconnection must take place no later than two 
 55.16  weeks following the completion of the upgrade.  The utility 
 55.17  shall employ best reasonable efforts to complete the system 
 55.18  upgrade in the shortest time reasonably practical. 
 55.19     (e) A utility shall use best reasonable efforts to 
 55.20  interconnect facilities within the time frames described in this 
 55.21  section.  If in a particular instance, a utility determines that 
 55.22  it cannot interconnect a facility within the time frames stated 
 55.23  in this section, it must notify the applicant in writing of that 
 55.24  fact.  The notification must identify any reasons 
 55.25  interconnection could not be performed in accordance with the 
 55.26  schedule and provide an estimated date for interconnection. 
 55.27     (f) Applications for interconnection and parallel operation 
 55.28  of distributed generation must be processed by the utility in a 
 55.29  nondiscriminatory manner and in the order that they are 
 55.30  received.  It is recognized that certain applications may 
 55.31  require minor modifications while they are being reviewed by the 
 55.32  utility.  These minor modifications to a pending application do 
 55.33  not require that it be considered incomplete and treated as a 
 55.34  new or separate application. 
 55.35     Sec. 8.  [216B.75] [REPORTING REQUIREMENTS.] 
 55.36     (a) Each electric utility shall maintain records concerning 
 56.1   applications received for interconnection and parallel operation 
 56.2   of distributed generation.  The records must include the date 
 56.3   each application is received, documents generated in the course 
 56.4   of processing each application, correspondence regarding each 
 56.5   application, and the final disposition of each application.  
 56.6      (b) By March 30 of each year, every electric utility shall 
 56.7   file with the commission a distributed generation 
 56.8   interconnection report for the preceding calendar year that 
 56.9   identifies each distributed generation facility interconnected 
 56.10  with the utility's distribution system.  The report must list 
 56.11  the new distributed generation facilities interconnected with 
 56.12  the system since the previous year's report, any distributed 
 56.13  generation facilities no longer interconnected with the 
 56.14  utility's system since the previous report, the capacity of each 
 56.15  facility, and the feeder or other point on the company's utility 
 56.16  system where the facility is connected.  The annual report must 
 56.17  also identify all applications for interconnection received 
 56.18  during the previous one-year period, and the disposition of the 
 56.19  applications. 
 56.20                             ARTICLE 5 
 56.21                       CONFORMING AMENDMENTS 
 56.22     Section 1.  Minnesota Statutes 2000, section 116C.61, 
 56.23  subdivision 1, is amended to read: 
 56.24     Subdivision 1.  [REGIONAL, COUNTY AND LOCAL ORDINANCES, 
 56.25  RULES, REGULATIONS; PRIMARY RESPONSIBILITY AND REGULATION OF 
 56.26  SITE DESIGNATION, IMPROVEMENT, AND USE.] To assure the paramount 
 56.27  and controlling effect of the provisions herein this section 
 56.28  over other state agencies,; regional, county, and local 
 56.29  governments,; and special purpose government districts, the 
 56.30  issuance of a certificate of site compatibility permit or 
 56.31  transmission line construction route permit and subsequent 
 56.32  purchase and use of such site or route locations for large 
 56.33  electric power generating plant and high voltage transmission 
 56.34  line purposes shall be is the sole site approval required to be 
 56.35  obtained by the utility.  Such certificate or The permit shall 
 56.36  supersede supersedes and preempt all preempts any zoning, 
 57.1   building, or land use rules, regulations, or ordinances 
 57.2   promulgated by any regional, county, local, and special purpose 
 57.3   government. 
 57.4      Sec. 2.  Minnesota Statutes 2000, section 116C.62, is 
 57.5   amended to read: 
 57.6      116C.62 [IMPROVEMENT OF SITES AND ROUTES.] 
 57.7      Utilities which that have acquired a site or route in 
 57.8   accordance with sections 116C.51 to 116C.69 may proceed to 
 57.9   construct or improve the site or route for the intended purposes 
 57.10  at any time, subject to section 116C.61, subdivision 2,; 
 57.11  provided that, if the construction and improvement commences 
 57.12  more than has not commenced within four years after a 
 57.13  certificate or permit for the site or route has been issued, 
 57.14  then the utility must certify to the board that the site or 
 57.15  route continues to meet the conditions upon which the 
 57.16  certificate of site compatibility or transmission line 
 57.17  construction permit was issued. 
 57.18     Sec. 3.  Minnesota Statutes 2000, section 116C.64, is 
 57.19  amended to read: 
 57.20     116C.64 [FAILURE TO ACT.] 
 57.21     If the board fails to act within the times specified in 
 57.22  section 116C.57, the applicant or any affected utility person 
 57.23  may seek an order of the district court requiring the board to 
 57.24  designate or refuse to designate a site or route. 
 57.25     Sec. 4.  Minnesota Statutes 2000, section 116C.645, is 
 57.26  amended to read: 
 57.27     116C.645 [REVOCATION OR SUSPENSION.] 
 57.28     A site certificate permit or construction route permit may 
 57.29  be revoked or suspended by the board after adequate notice of 
 57.30  the alleged grounds for revocation or suspension and a full and 
 57.31  fair hearing in which the affected utility has an opportunity to 
 57.32  confront any witness and respond to any evidence against it and 
 57.33  to present rebuttal or mitigating evidence upon a finding by the 
 57.34  board of: 
 57.35     (1) any false statement knowingly made in the application 
 57.36  or in accompanying statements or studies required of the 
 58.1   applicant, if a true statement would have warranted a change in 
 58.2   the board's findings; 
 58.3      (2) failure to comply with material conditions of the site 
 58.4   certificate or construction permit, or failure to maintain 
 58.5   health and safety standards; or 
 58.6      (3) any material violation of the provisions of sections 
 58.7   116C.51 to 116C.69, any rule promulgated pursuant thereto 
 58.8   adopted under these sections, or any order of the board. 
 58.9      Sec. 5.  Minnesota Statutes 2000, section 116C.65, is 
 58.10  amended to read: 
 58.11     116C.65 [JUDICIAL REVIEW.] 
 58.12     Any utility applicant, party, or person aggrieved by the 
 58.13  issuance of a certificate site or route permit or emergency 
 58.14  certificate of site compatibility or transmission line 
 58.15  construction permit from the board or a certification of 
 58.16  continuing suitability filed by a utility with the board or by a 
 58.17  final order in accordance with any rules promulgated adopted by 
 58.18  the board, may appeal to the court of appeals in accordance with 
 58.19  chapter 14.  The appeal shall must be filed within 60 days after 
 58.20  the publication in the State Register of notice of the issuance 
 58.21  of the certificate or permit by the board or certification filed 
 58.22  with the board or the filing of any final order by the board.  
 58.23     Sec. 6.  Minnesota Statutes 2000, section 116C.66, is 
 58.24  amended to read: 
 58.25     116C.66 [RULES.] 
 58.26     (a) The board, in order to give effect to the purposes of 
 58.27  sections 116C.51 to 116C.69, shall prior to July 1, 1978, may 
 58.28  adopt rules consistent with sections 116C.51 to 116C.69, 
 58.29  including promulgation adoption of site and route designation 
 58.30  criteria,; the description of the information to be furnished by 
 58.31  the utilities,; establishment of minimum guidelines for public 
 58.32  participation in the development, revision, and enforcement of 
 58.33  any rule, plan, or program established by the board,; procedures 
 58.34  for the revocation or suspension of a construction permit or a 
 58.35  certificate of site compatibility,; the procedure and timeliness 
 58.36  for proposing alternative routes and sites,; and route exemption 
 59.1   criteria and procedures. 
 59.2      No (b) A rule adopted by the board shall may not grant 
 59.3   priority to state-owned wildlife management areas over 
 59.4   agricultural lands in the designation of route-avoidance areas. 
 59.5      (c) The provisions of chapter 14 shall apply to the appeal 
 59.6   of rules adopted by the board to the same extent as it applies 
 59.7   to the review of rules adopted by any other agency of state 
 59.8   government. 
 59.9      (d) The chief administrative law judge shall, prior to 
 59.10  January 1, 1978, adopt procedural rules for public hearings 
 59.11  relating to the site and route designation process and to the 
 59.12  route exemption process.  The rules shall must attempt to 
 59.13  maximize citizen participation in these processes. 
 59.14     Sec. 7.  Minnesota Statutes 2000, section 116C.69, is 
 59.15  amended to read: 
 59.16     116C.69 [BIENNIAL REPORT; APPLICATION FEES; APPROPRIATION; 
 59.17  FUNDING.] 
 59.18     Subdivision 1.  [BIENNIAL REPORT.] Before November 15 of 
 59.19  each even-numbered year the board shall prepare and submit to 
 59.20  the legislature a report of its operations, activities, 
 59.21  findings, and recommendations concerning sections 116C.51 to 
 59.22  116C.69.  The report shall also contain information on the 
 59.23  board's biennial expenditures, its proposed budget for the 
 59.24  following biennium, and the amounts paid in certificate and 
 59.25  permit application fees pursuant to subdivisions 2 and 2a and in 
 59.26  assessments pursuant to subdivision 3 section 116C.69.  The 
 59.27  proposed budget for the following biennium shall be is subject 
 59.28  to legislative review. 
 59.29     Subd. 2.  [SITE APPLICATION FEE.] Every applicant for a 
 59.30  site certificate permit shall pay to the board a fee in an 
 59.31  amount equal to $500 for each $1,000,000 of production plant 
 59.32  investment in the proposed installation as defined in the 
 59.33  Federal Power Commission Uniform System of Accounts.  The board 
 59.34  shall specify the time and manner of payment of the fee.  If any 
 59.35  single payment requested by the board is in excess of 25 percent 
 59.36  of the total estimated fee, the board shall show that the excess 
 60.1   is reasonably necessary.  The applicant shall pay within 30 days 
 60.2   of notification any additional fees reasonably necessary for 
 60.3   completion of the site evaluation and designation process by the 
 60.4   board.  In no event shall The total fees required of the 
 60.5   applicant under this subdivision must never exceed an amount 
 60.6   equal to 0.001 of said the production plant investment (, which 
 60.7   equals $1,000 for each $1,000,000).  All money received pursuant 
 60.8   to under this subdivision shall must be deposited in a special 
 60.9   account.  Money in the account is appropriated to the board to 
 60.10  pay expenses incurred in processing applications 
 60.11  for certificates site permits in accordance with sections 
 60.12  116C.51 to 116C.69 and in the event, if the expenses are less 
 60.13  than the fee paid, to refund the excess to the applicant.  
 60.14     Subd. 2a.  [ROUTE APPLICATION FEE.] Every applicant for a 
 60.15  transmission line construction route permit shall pay to the 
 60.16  board a base fee of $35,000 plus a fee in an amount equal to 
 60.17  $1,000 per mile length of the longest proposed route.  The board 
 60.18  shall specify the time and manner of payment of the fee.  If any 
 60.19  single payment requested by the board is in excess of 25 percent 
 60.20  of the total estimated fee, the board shall show that the excess 
 60.21  is reasonably necessary.  In the event If the actual cost of 
 60.22  processing an application up to the board's final decision to 
 60.23  designate a route exceeds the above this fee schedule, the board 
 60.24  may assess the applicant any additional fees necessary to cover 
 60.25  the actual costs, not to exceed an amount equal to $500 per mile 
 60.26  length of the longest proposed route.  All money received 
 60.27  pursuant to under this subdivision shall must be deposited in a 
 60.28  special account.  Money in the account is appropriated to the 
 60.29  board to pay expenses incurred in processing applications for 
 60.30  construction route permits in accordance with sections 116C.51 
 60.31  to 116C.69 and in the event, if the expenses are less than the 
 60.32  fee paid, to refund the excess to the applicant.  
 60.33     Subd. 3.  [FUNDING; ASSESSMENT.] (a) The board shall 
 60.34  finance its base line studies, general environmental studies, 
 60.35  development of criteria, inventory preparation, monitoring of 
 60.36  conditions placed on site certificates and construction route 
 61.1   permits, and all other work, other than specific site and route 
 61.2   designation, from an assessment made quarterly, at least 30 days 
 61.3   before the start of each quarter, by the board against all 
 61.4   utilities with annual retail kilowatt-hour sales greater than 
 61.5   4,000,000 kilowatt-hours in the previous calendar year.  
 61.6      (b) Each share shall must be determined as follows: 
 61.7      (1) the ratio that the annual retail kilowatt-hour sales in 
 61.8   the state of each utility bears to the annual total retail 
 61.9   kilowatt-hour sales in the state of all these utilities, 
 61.10  multiplied by 0.667,; plus 
 61.11     (2) the ratio that the annual gross revenue from retail 
 61.12  kilowatt-hour sales in the state of each utility bears to the 
 61.13  annual total gross revenues from retail kilowatt-hour sales in 
 61.14  the state of all these utilities, multiplied by 0.333, as 
 61.15  determined by the board. 
 61.16     (c) The assessment shall must be credited to the special 
 61.17  revenue fund and shall be paid to the state treasury within 30 
 61.18  days after receipt of the bill, which shall constitute notice of 
 61.19  said the assessment and its demand of payment thereof. 
 61.20     (d) The total amount which that may be assessed to the 
 61.21  several utilities under the authority of this subdivision shall 
 61.22  may not exceed the sum of the annual budget of the board for 
 61.23  carrying out the purposes of this subdivision. 
 61.24     (e) The assessment for the second quarter of each fiscal 
 61.25  year shall must be adjusted to compensate for the amount by 
 61.26  which actual expenditures by the board for the preceding fiscal 
 61.27  year were more or less than the estimated expenditures 
 61.28  previously assessed. 
 61.29     Sec. 8.  Minnesota Statutes 2000, section 216B.03, is 
 61.30  amended to read: 
 61.31     216B.03 [REASONABLE RATE.] 
 61.32     (a) Every rate made, demanded, or received by any public 
 61.33  utility, or by any two or more public utilities jointly, shall 
 61.34  must be just and reasonable.  Rates shall must not be 
 61.35  unreasonably preferential, or unreasonably prejudicial or 
 61.36  discriminatory, but shall must be sufficient, equitable, and 
 62.1   consistent in application to a class of consumers.  To the 
 62.2   maximum reasonable extent, the commission shall set rates to 
 62.3   encourage energy conservation and renewable energy use and to 
 62.4   further the goals of sections 216B.164, 216B.241, 216B.2411, and 
 62.5   216C.05.  Any doubt as to reasonableness should be resolved in 
 62.6   favor of the consumer. 
 62.7      (b) For rate-making purposes a public utility may treat two 
 62.8   or more municipalities served by it as a single class wherever 
 62.9   the populations are comparable in size or the conditions of 
 62.10  service are similar.  
 62.11     Sec. 9.  Minnesota Statutes 2000, section 216B.16, 
 62.12  subdivision 1, is amended to read: 
 62.13     Subdivision 1.  [NOTICE.] Unless the commission otherwise 
 62.14  orders, no public utility shall change a rate which that has 
 62.15  been duly established under this chapter, except upon 60 days' 
 62.16  notice to the commission.  The notice shall must include 
 62.17  statements of facts, expert opinions, substantiating documents, 
 62.18  and exhibits, supporting the change requested, and state the 
 62.19  change proposed to be made in the rates then in force and the 
 62.20  time when the modified rates will go into effect.  If the filing 
 62.21  utility does not have an approved conservation improvement plan 
 62.22  on file with the department of public service, it shall also 
 62.23  include in its notice an energy conservation plan pursuant to 
 62.24  section 216B.241.  The filing utility shall give written notice, 
 62.25  as approved by the commission, of the proposed change to the 
 62.26  governing body of each municipality and county in the area 
 62.27  affected.  All proposed changes shall must be shown by filing 
 62.28  new schedules or shall be plainly indicated upon schedules on 
 62.29  file and in force at the time. 
 62.30     Sec. 10.  Minnesota Statutes 2000, section 216B.16, 
 62.31  subdivision 6b, is amended to read: 
 62.32     Subd. 6b.  [ENERGY CONSERVATION IMPROVEMENT.] (a) Except as 
 62.33  otherwise provided in this subdivision, all investments and 
 62.34  expenses of a public utility as defined in section 216B.241, 
 62.35  subdivision 1, paragraph (e), incurred in connection with energy 
 62.36  conservation improvements shall under either section 216B.241 or 
 63.1   216B.2411 must be recognized and included by the commission in 
 63.2   the determination of just and reasonable rates as if the 
 63.3   investments and expenses were directly made or incurred by the 
 63.4   utility in furnishing utility service. 
 63.5      (b) After December 31, 1999, investments and expenses for 
 63.6   energy conservation improvements shall must not be included by 
 63.7   the commission in the determination of just and reasonable 
 63.8   electric and gas rates for retail electric and gas service 
 63.9   provided to large electric customer facilities that have been 
 63.10  exempted by the commissioner of the department of public service 
 63.11  pursuant to section 216B.241, subdivision 1a, paragraph (b).  
 63.12  However, no a public utility shall may not be prevented from 
 63.13  recovering its investment in energy conservation improvements 
 63.14  from all customers that were made on or before December 31, 
 63.15  1999, in compliance with the requirements of section 216B.241.  
 63.16     (c) The commission may permit a public utility to file rate 
 63.17  schedules providing for annual recovery of the costs of energy 
 63.18  conservation improvements under either section 216B.241 or 
 63.19  216B.2411.  These rate schedules may be applicable to less than 
 63.20  all the customers in a class of retail customers if necessary to 
 63.21  reflect the differing minimum spending requirements of section 
 63.22  216B.241, subdivision 1a.  After December 31, 1999, the 
 63.23  commission shall allow a public utility, without requiring a 
 63.24  general rate filing under this section, to reduce the electric 
 63.25  and gas rates applicable to large electric customer facilities 
 63.26  that have been exempted by the commissioner of the department of 
 63.27  public service pursuant to section 216B.241, subdivision 1a, 
 63.28  paragraph (b), by an amount that reflects the elimination of 
 63.29  energy conservation improvement investments or expenditures for 
 63.30  those facilities required on or before December 31, 1999.  In 
 63.31  the event that If the commission has set electric or gas rates 
 63.32  based on the use of an accounting methodology that results in 
 63.33  the cost of conservation improvements being recovered from 
 63.34  utility customers over a period of years, the rate reduction may 
 63.35  occur in a series of steps to coincide with the recovery of 
 63.36  balances due to the utility for conservation improvements made 
 64.1   by the utility on or before December 31, 1999.  
 64.2      Sec. 11.  Minnesota Statutes 2000, section 216B.16, 
 64.3   subdivision 6c, is amended to read: 
 64.4      Subd. 6c.  [INCENTIVE PLAN FOR ENERGY CONSERVATION 
 64.5   IMPROVEMENT.] (a) The commission may order public utilities to 
 64.6   develop and submit for commission approval incentive plans that 
 64.7   describe the method of recovery and accounting for utility 
 64.8   conservation expenditures and savings under either section 
 64.9   216B.241 or 216B.2411.  In developing the incentive plans the 
 64.10  commission shall ensure the effective involvement of interested 
 64.11  parties. 
 64.12     (b) In approving incentive plans, the commission shall 
 64.13  consider: 
 64.14     (1) whether the plan is likely to increase utility 
 64.15  investment in cost-effective energy conservation; 
 64.16     (2) whether the plan is compatible with the interest of 
 64.17  utility ratepayers and other interested parties; 
 64.18     (3) whether the plan links the incentive to the utility's 
 64.19  performance in achieving cost-effective conservation; and 
 64.20     (4) whether the plan is in conflict with other provisions 
 64.21  of this chapter. 
 64.22     (c) The commission may set rates to encourage the vigorous 
 64.23  and effective implementation of utility conservation programs.  
 64.24  The commission may: 
 64.25     (1) increase or decrease any otherwise allowed rate of 
 64.26  return on net investment based upon the utility's skill, 
 64.27  efforts, and success in conserving energy; 
 64.28     (2) share between ratepayers and utilities the net savings 
 64.29  resulting from energy conservation programs to the extent 
 64.30  justified by the utility's skill, efforts, and success in 
 64.31  conserving energy; and 
 64.32     (3) compensate the utility for earnings lost as a result of 
 64.33  its conservation programs. 
 64.34     Sec. 12.  Minnesota Statutes 2000, section 216B.162, 
 64.35  subdivision 8, is amended to read: 
 64.36     Subd. 8.  [ENERGY EFFICIENCY IMPROVEMENT; EXPENSE 
 65.1   RECOVERY.] If the commission approves a competitive rate or the 
 65.2   parties agree to a modified rate, the commission may require the 
 65.3   electric utility to provide the customer with an energy audit 
 65.4   and assist in implementing cost-effective energy efficiency 
 65.5   improvements to assure that the customer's use of electricity is 
 65.6   efficient.  An investment in cost-effective energy conservation 
 65.7   improvements required under this section must be treated as an 
 65.8   energy conservation improvement program and included in 
 65.9   the department's determination of significant investments under 
 65.10  section 216B.241 or 216B.2411.  The utility shall recover energy 
 65.11  conservation improvement expenses in a rate proceeding under 
 65.12  section 216B.16 or 216B.17 in the same manner as the commission 
 65.13  authorizes for the recovery of conservation expenditures made 
 65.14  under section 216B.241 or 216B.2411. 
 65.15     Sec. 13.  Minnesota Statutes 2000, section 216B.1621, 
 65.16  subdivision 2, is amended to read: 
 65.17     Subd. 2.  [COMMISSION APPROVAL.] (a) The commission shall 
 65.18  approve an agreement under this section upon finding that: 
 65.19     (1) the proposed electric service power generation facility 
 65.20  could reasonably be expected to qualify for a market value 
 65.21  exclusion under section 272.0211; 
 65.22     (2) the public utility has a contractual option to purchase 
 65.23  electric power from the proposed facility; and 
 65.24     (3) the public utility can use the output from the proposed 
 65.25  facility to meet its future need for power as demonstrated in 
 65.26  the most recent resource plan filed with and approved by the 
 65.27  commission under section 216B.2422. 
 65.28     (b) Sections 216B.03, 216B.05, 216B.06, 216B.07, 216B.16, 
 65.29  216B.162, and 216B.23 do not apply to an agreement under this 
 65.30  section. 
 65.31     Sec. 14.  Minnesota Statutes 2000, section 216B.164, 
 65.32  subdivision 4, is amended to read: 
 65.33     Subd. 4.  [PURCHASES; WHEELING; COSTS.] (a) Except as 
 65.34  otherwise provided in paragraph (c), this subdivision shall 
 65.35  apply to all qualifying facilities having 40-kilowatt capacity 
 65.36  or more as well as qualifying facilities as defined in 
 66.1   subdivision 3 which elect to be governed by its provisions.  
 66.2      (b) The utility to which the qualifying facility is 
 66.3   interconnected shall purchase all energy and capacity made 
 66.4   available by the qualifying facility.  The qualifying facility 
 66.5   shall be paid the utility's full avoided capacity and energy 
 66.6   costs as negotiated by the parties, as set by the commission, or 
 66.7   as determined through competitive bidding approved by the 
 66.8   commission.  The full avoided capacity and energy costs to be 
 66.9   paid a qualifying facility that generates electric power by 
 66.10  means of a renewable energy source are the utility's least cost 
 66.11  renewable energy facility or the bid of a competing supplier of 
 66.12  a least cost renewable energy facility, whichever is lower, 
 66.13  unless the commission's resource plan order, under section 
 66.14  216B.2422, subdivision 2, provides commission determines that 
 66.15  the use of a renewable resource to meet the identified capacity 
 66.16  need is not in the public interest.  
 66.17     (c) For all qualifying facilities having 30-kilowatt 
 66.18  capacity or more, the utility shall, at the qualifying 
 66.19  facility's or the utility's request, provide wheeling or 
 66.20  exchange agreements wherever practicable to sell the qualifying 
 66.21  facility's output to any other Minnesota utility having 
 66.22  generation expansion anticipated or planned for the ensuing ten 
 66.23  years.  The commission shall establish the methods and 
 66.24  procedures to insure that except for reasonable wheeling charges 
 66.25  and line losses, the qualifying facility receives the full 
 66.26  avoided energy and capacity costs of the utility ultimately 
 66.27  receiving the output.  
 66.28     (d) The commission shall set rates for electricity 
 66.29  generated by renewable energy. 
 66.30     Sec. 15.  Minnesota Statutes 2000, section 216B.2423, 
 66.31  subdivision 2, is amended to read: 
 66.32     Subd. 2.  [RESOURCE PLANNING MANDATE.] The public utilities 
 66.33  commission shall order a public utility subject to subdivision 
 66.34  1, to construct and operate, purchase, or contract to purchase 
 66.35  an additional 400 megawatts of electric energy installed 
 66.36  capacity generated by wind energy conversion systems by December 
 67.1   31, 2002, subject to any resource planning and least cost 
 67.2   planning requirements in section 216B.2422. 
 67.3      Sec. 16.  Minnesota Statutes 2000, section 216C.17, 
 67.4   subdivision 3, is amended to read: 
 67.5      Subd. 3.  [DUPLICATION.] The commissioner shall, to the 
 67.6   maximum extent feasible, provide that forecasts required under 
 67.7   this section be consistent with material required by other state 
 67.8   and federal agencies in order to prevent unnecessary 
 67.9   duplication.  Electric utilities submitting advance forecasts as 
 67.10  part of an integrated resource plan filed pursuant to section 
 67.11  216B.2422 and public utilities commission rules are excluded 
 67.12  from the annual reporting requirement in subdivision 2. 
 67.13     Sec. 17.  [INSTRUCTION TO REVISOR.] 
 67.14     The revisor of statutes shall renumber Minnesota Statutes, 
 67.15  section 116C.69, subdivision 1, as Minnesota Statutes, section 
 67.16  116C.681. 
 67.17                             ARTICLE 6
 67.18                      MISCELLANEOUS PROVISIONS
 67.19     Section 1.  Minnesota Statutes 2000, section 216A.03, 
 67.20  subdivision 3a, is amended to read: 
 67.21     Subd. 3a.  [POWERS AND DUTIES OF CHAIR.] The chair shall be 
 67.22  is the principal executive officer of the commission and shall 
 67.23  preside at meetings of the commission.  The responsibilities of 
 67.24  the chair shall organize include: 
 67.25     (1) organizing the work of the commission and may make; 
 67.26     (2) making assignments to commission members, appoint 
 67.27  committees and give as appropriate; 
 67.28     (3) appointing subcommittees; 
 67.29     (4) giving direction to the commission staff through the 
 67.30  executive secretary subject to the approval of the commission.; 
 67.31     (5) supervising the work of the executive secretary; and 
 67.32     (6) in coordination with the executive secretary, 
 67.33  participating in employment and termination decisions, including 
 67.34  representing the commission in grievance proceedings; addressing 
 67.35  employee complaints and grievances; developing and implementing 
 67.36  the agency budget; testifying before legislative committees and 
 68.1   working with legislators as requested; determining agency-wide 
 68.2   training needs and initiatives; implementing computer technology 
 68.3   updates; administering and implementing relations with the 
 68.4   department of commerce, the office of the attorney general, and 
 68.5   other agencies; and developing and implementing strategies for 
 68.6   the commission to adapt to rapid changes in the industries the 
 68.7   commission oversees. 
 68.8      Sec. 2.  Minnesota Statutes 2000, section 216B.095, is 
 68.9   amended to read: 
 68.10     216B.095 [DISCONNECTION DURING COLD WEATHER.] 
 68.11     The commission shall amend its rules governing 
 68.12  disconnection of residential utility customers who are unable to 
 68.13  pay for utility service during cold weather to include the 
 68.14  following: 
 68.15     (1) coverage of customers whose household income is less 
 68.16  than 185 percent of the federal poverty level 50 percent of the 
 68.17  state median income; 
 68.18     (2) a requirement that a customer who pays the utility at 
 68.19  least ten percent of the customer's income or the full amount of 
 68.20  the utility bill, whichever is less, in a cold weather month 
 68.21  cannot be disconnected during that month; 
 68.22     (3) that the ten percent figure in clause (2) must be 
 68.23  prorated between energy providers proportionate to each 
 68.24  provider's share of the customer's total energy costs where the 
 68.25  customer receives service from more than one provider; 
 68.26     (4) that a customer's household income does not include any 
 68.27  amount received for energy assistance; 
 68.28     (5) (4) verification of income by the local energy 
 68.29  assistance provider or the utility, unless the customer is 
 68.30  automatically eligible for protection against disconnection as a 
 68.31  recipient of any form of public assistance, including energy 
 68.32  assistance, that uses income eligibility in an amount at or 
 68.33  below the income eligibility in clause (1); and 
 68.34     (6) (5) a requirement that the customer receive, from the 
 68.35  local energy assistance provider or other entity, budget 
 68.36  counseling and referral referrals to energy assistance programs, 
 69.1   weatherization, conservation, or other programs likely to reduce 
 69.2   the customer's consumption of energy bills; 
 69.3      (6) a requirement that customers who have demonstrated an 
 69.4   inability to pay on forms for such purposes provided by the 
 69.5   utility, and who make reasonably timely payments to the utility 
 69.6   under a payment plan that considers the financial resources of 
 69.7   the household, cannot be disconnected from utility services from 
 69.8   October 15 to April 15.  A customer who is receiving energy 
 69.9   assistance is deemed to have demonstrated an inability to pay. 
 69.10  For the purpose of clause (2), the "customer's income" means the 
 69.11  actual monthly income of the customer except for a customer who 
 69.12  is normally employed only on a seasonal basis and whose annual 
 69.13  income is over 135 percent of the federal poverty level, in 
 69.14  which case the customer's income is or the average monthly 
 69.15  income of the customer computed on an annual calendar year 
 69.16  basis, whichever is less, and does not include any amount 
 69.17  received for energy assistance. 
 69.18     Sec. 3.  Minnesota Statutes 2000, section 216B.097, 
 69.19  subdivision 1, is amended to read: 
 69.20     Subdivision 1.  [APPLICATION; NOTICE TO RESIDENTIAL 
 69.21  CUSTOMER.] (a) A municipal utility or a cooperative electric 
 69.22  association must not disconnect the utility service of a 
 69.23  residential customer during the period between October 15 and 
 69.24  April 15 if the disconnection affects the primary heat source 
 69.25  for the residential unit when the following conditions are met: 
 69.26     (1) the disconnection would occur during the period between 
 69.27  October 15 and April 15; 
 69.28     (2) (1) the customer has declared inability to pay on forms 
 69.29  provided by the utility.  For the purpose of this clause, a 
 69.30  customer that is receiving energy assistance is deemed to have 
 69.31  demonstrated an inability to pay; 
 69.32     (3) (2) the household income of the customer is less than 
 69.33  185 percent of the federal poverty level, as documented by the 
 69.34  customer to the utility; and 50 percent of the state median 
 69.35  income; 
 69.36     (3) verification of income may be conducted by the local 
 70.1   energy assistance provider or the utility, unless the customer 
 70.2   is automatically eligible for protection against disconnection 
 70.3   as a recipient of any form of public assistance, including 
 70.4   energy assistance, that uses income eligibility in an amount at 
 70.5   or below the income eligibility in clause (2); 
 70.6      (4) the customer's a customer whose account is current for 
 70.7   the billing period immediately prior to October 15 or the 
 70.8   customer has entered enters into a payment schedule that 
 70.9   considers the financial resources of the household and is 
 70.10  reasonably current with payments under the schedule; and 
 70.11     (5) the customer receives referrals to energy assistance 
 70.12  programs, and weatherization, conservation, or other programs to 
 70.13  reduce the customer's energy bills. 
 70.14     (b) A municipal utility or a cooperative electric 
 70.15  association must, between August 15 and October 15 of each year, 
 70.16  notify all residential customers of the provisions of this 
 70.17  section. 
 70.18     Sec. 4.  [216B.098] [CUSTOMER PROTECTIONS.] 
 70.19     Subdivision 1.  [APPLICABILITY.] This section applies to 
 70.20  residential customers of public utilities, municipal utilities, 
 70.21  and cooperative electric associations. 
 70.22     Subd. 2.  [BUDGET BILLING PLANS.] A utility shall offer a 
 70.23  customer a budget billing plan for payment of charges for 
 70.24  service, including adequate notice to customers prior to 
 70.25  changing budget payment amounts.  Municipal utilities having 
 70.26  3,000 or fewer customers are exempt from this requirement.  
 70.27  Municipal utilities having more than 3,000 customers shall 
 70.28  implement this requirement within two years of the effective 
 70.29  date of this chapter. 
 70.30     Subd. 3.  [PAYMENT AGREEMENTS.] A utility shall offer a 
 70.31  payment agreement for the payment of arrears. 
 70.32     Subd. 4.  [UNDERCHARGES.] A utility shall offer a payment 
 70.33  agreement to customers who have been undercharged if no culpable 
 70.34  conduct by the customer or resident of the customer's household 
 70.35  caused the undercharge.  The agreement must cover a period equal 
 70.36  to the time over which the undercharge occurred or a different 
 71.1   time period that is mutually agreeable to the customer and the 
 71.2   utility.  No interest or delinquency fee may be charged under 
 71.3   this agreement. 
 71.4      Subd. 5.  [MEDICALLY NECESSARY EQUIPMENT.] A utility shall 
 71.5   reconnect or continue service to a customer's residence where a 
 71.6   medical emergency exists or where medical equipment requiring 
 71.7   electricity is necessary to sustain life is in use, provided 
 71.8   that the utility receives from a medical doctor written 
 71.9   certification, or initial certification by telephone and written 
 71.10  certification within five business days, that failure to 
 71.11  reconnect or continue service will impair or threaten the health 
 71.12  or safety of a resident of the customer's household.  The 
 71.13  customer must enter into a payment agreement. 
 71.14     Subd. 6.  [COMMISSION AUTHORITY.] The commission, or staff 
 71.15  designated by the commission, has the authority to order 
 71.16  resolutions of disputes involving alleged violations of this 
 71.17  chapter or any other disputes involving public utilities coming 
 71.18  within its jurisdiction. 
 71.19     Sec. 5.  [216B.79] [PREVENTATIVE MAINTENANCE.] 
 71.20     (a) The commission has the authority to ensure that public 
 71.21  utilities are making adequate infrastructure investments and 
 71.22  undertaking sufficient preventative maintenance with regard to 
 71.23  such facilities.  
 71.24     (b) The commission may make appropriate adjustments in a 
 71.25  utility's rates, or make a recommendation to the Federal Energy 
 71.26  Regulatory Commission to make an appropriate adjustment in a 
 71.27  utility's allowed rate of return on those utilities' 
 71.28  transmission facilities, to offset the costs of such 
 71.29  construction. 
 71.30     Sec. 6.  Minnesota Statutes 2000, section 216C.41, is 
 71.31  amended to read: 
 71.32     216C.41 [RENEWABLE ENERGY PRODUCTION INCENTIVE.] 
 71.33     Subdivision 1.  [DEFINITIONS.] (a) The definitions in this 
 71.34  subdivision apply to this section. 
 71.35     (b) "Qualified hydroelectric facility" means a 
 71.36  hydroelectric generating facility in this state that: 
 72.1      (1) is located at the site of a dam, if the dam was in 
 72.2   existence as of March 31, 1994; and 
 72.3      (2) either (i) begins generating electricity after July 1, 
 72.4   1994; or (ii) is generating electricity as of June 30, 2001, and 
 72.5   undergoes substantial refurbishing after that date, to be 
 72.6   completed by December 31, 2005. 
 72.7      (c) "Qualified wind energy conversion facility" means a 
 72.8   wind energy conversion system that: 
 72.9      (1) produces two megawatts or less of electricity as 
 72.10  measured by nameplate rating and begins generating electricity 
 72.11  after June 30, 1997, and before July 1, 1999; 
 72.12     (2) begins generating electricity after June 30, 1999, 
 72.13  produces two megawatts or less of electricity as measured by 
 72.14  nameplate rating, and is: 
 72.15     (i) located within one county and owned by a natural person 
 72.16  who owns the land where the facility is sited; 
 72.17     (ii) owned by a Minnesota small business as defined in 
 72.18  section 645.445; 
 72.19     (iii) owned by a nonprofit organization; or 
 72.20     (iv) owned by a tribal council if the facility is located 
 72.21  within the boundaries of the reservation; or 
 72.22     (3) begins generating electricity after June 30, 1999, 
 72.23  produces seven megawatts or less of electricity as measured by 
 72.24  nameplate rating, and: 
 72.25     (i) is owned by a cooperative organized under chapter 308A; 
 72.26  and 
 72.27     (ii) all shares and membership in the cooperative are held 
 72.28  by natural persons or estates, at least 51 percent of whom 
 72.29  reside in a county or contiguous to a county where the wind 
 72.30  energy production facilities of the cooperative are located. 
 72.31     Subd. 2.  [INCENTIVE PAYMENT.] (a) Incentive payments shall 
 72.32  be made according to this section to the owner or operator of a 
 72.33  qualified hydropower facility or qualified wind energy 
 72.34  conversion facility for electric energy generated and sold by 
 72.35  the facility or, except as provided in paragraph (b) for a 
 72.36  publicly owned hydropower facility, for electric energy that is 
 73.1   generated by the facility and used by the owner of the facility 
 73.2   outside the facility.  
 73.3      (b) For a facility that is publicly owned and in need of 
 73.4   substantial refurbishment and repair, the incentive payment 
 73.5   shall be made to the public owner of the facility to finance 
 73.6   structural repairs and replacement of structural components. 
 73.7      (c) Payment may only be made upon receipt by the 
 73.8   commissioner of finance of an incentive payment application that 
 73.9   establishes that the applicant is eligible to receive an 
 73.10  incentive payment and that satisfies other requirements the 
 73.11  commissioner deems necessary.  The application shall be in a 
 73.12  form and submitted at a time the commissioner establishes.  
 73.13  There is annually appropriated from the general fund sums 
 73.14  sufficient to make the payments required under this section.  
 73.15     Subd. 3.  [ELIGIBILITY WINDOW.] Payments may be made under 
 73.16  this section only for electricity generated: 
 73.17     (1) from a qualified hydroelectric facility that is 
 73.18  operational and generating electricity before December 31, 2001, 
 73.19  or that undergoes substantial refurbishing after June 30, 2001, 
 73.20  to be completed by December 31, 2005; or 
 73.21     (2) from a qualified wind energy conversion facility that 
 73.22  is operational and generating electricity before January 1, 2005.
 73.23     Subd. 4.  [PAYMENT PERIOD.] A facility may receive payments 
 73.24  under this section for a ten-year period.  No payment under this 
 73.25  section may be made for electricity generated: 
 73.26     (1) by a qualified hydroelectric facility after December 
 73.27  31, 2010, or December 31, 2015, if the facility undergoes 
 73.28  substantial refurbishing after June 30, 2001; or 
 73.29     (2) by a qualified wind energy conversion facility after 
 73.30  December 31, 2015.  
 73.31     The payment period begins and runs consecutively from the 
 73.32  first year in which electricity generated from the facility is 
 73.33  eligible for incentive payment. 
 73.34     Subd. 5.  [AMOUNT OF PAYMENT.] (a) An incentive payment is 
 73.35  based on the number of kilowatt hours of electricity generated. 
 73.36  The amount of the payment is 1.5 cents per kilowatt hour.  For 
 74.1   electricity generated by qualified wind energy conversion 
 74.2   facilities, the incentive payment under this section is limited 
 74.3   to no more than 100 megawatts of nameplate capacity.  During any 
 74.4   period in which qualifying claims for incentive payments exceed 
 74.5   100 megawatts of nameplate capacity, the payments must be made 
 74.6   to producers in the order in which the production capacity was 
 74.7   brought into production.  
 74.8      (b) Beginning July 1, 2001, a qualified wind energy 
 74.9   conversion facility defined under subdivision 1, paragraph (c), 
 74.10  clause (1), (2), or (3), may not be located within five miles of 
 74.11  another qualified wind energy conversion facility constructed 
 74.12  within the same calendar year and owned by the same person.  For 
 74.13  the purposes of this paragraph, the department shall determine 
 74.14  that the same person owns two qualified wind energy conversion 
 74.15  facilities when the underlying ownership structure contains 
 74.16  similar persons or entities, other than a person or entity that 
 74.17  provides equity financing, even if the ownership shares differ 
 74.18  between the facilities. 
 74.19     Subd. 6.  [OWNERSHIP; FINANCING; CURE.] (a) For the 
 74.20  purposes of subdivision 1, paragraph (c), clause (2), a wind 
 74.21  energy conversion facility qualifies if it is owned at least 51 
 74.22  percent by one or more of any combination of the entities listed 
 74.23  in that clause. 
 74.24     (b) A subsequent owner of a qualified facility may continue 
 74.25  to receive the incentive payment for the duration of the 
 74.26  original payment period if the subsequent owner qualifies for 
 74.27  the incentive under subdivision 1. 
 74.28     (c) Nothing in this section may be construed to deny 
 74.29  incentive payment to an otherwise qualified facility that has 
 74.30  obtained debt or equity financing for construction or operation 
 74.31  as long as the ownership requirements of subdivision 1 and this 
 74.32  subdivision are met.  If, during the incentive payment period 
 74.33  for a qualified facility, the owner of the facility is in 
 74.34  default of a lending agreement and the lender takes possession 
 74.35  of and operates the facility and makes reasonable efforts to 
 74.36  transfer ownership of the facility to an entity other than the 
 75.1   lender, the lender may continue to receive the incentive payment 
 75.2   for electricity generated and sold by the facility for a period 
 75.3   not to exceed 18 months.  A lender who takes possession of a 
 75.4   facility shall notify the commissioner immediately on taking 
 75.5   possession and, at least quarterly, document efforts to transfer 
 75.6   ownership of the facility. 
 75.7      (d) If, during the incentive payment period, a qualified 
 75.8   facility loses the right to receive the incentive because of 
 75.9   changes in ownership, the facility may regain the right to 
 75.10  receive the incentive upon cure of the ownership structure that 
 75.11  resulted in the loss of eligibility and may reapply for the 
 75.12  incentive, but in no case may the payment period be extended 
 75.13  beyond the original ten-year limit. 
 75.14     (e) A subsequent or requalifying owner under paragraph (b)  
 75.15  or (d) retains the facility's original priority order for 
 75.16  incentive payments as long as the ownership structure 
 75.17  requalifies within two years from the date the facility became 
 75.18  unqualified or two years from the date a lender takes possession 
 75.19  of the facility. 
 75.20     Sec. 7.  [REPEALER.] 
 75.21     (a) Minnesota Statutes 2000, sections 216B.241, subdivision 
 75.22  1c, and 216C.18, are repealed. 
 75.23     (b) Minnesota Statutes 2000, section 216B.2422, 
 75.24  subdivisions 2 and 6, are repealed September 1, 2002. 
 75.25     Sec. 8.  [EFFECTIVE DATE.] 
 75.26     Articles 3 to 6 are effective the day following final 
 75.27  enactment, except that those provisions referring or relating to 
 75.28  article 1, section 2 or 3, the independent reliability 
 75.29  administrator or the state reliability plan, are effective July 
 75.30  1, 2002. 
 75.31                             ARTICLE 7
 75.32                    SAFETY AND SERVICE STANDARDS
 75.33     Section 1.  [216B.81] [DEFINITIONS.] 
 75.34     Subdivision 1.  [SCOPE.] The terms used in this article 
 75.35  have the meanings given them in this section. 
 75.36     Subd. 2.  [AVERAGE NUMBER OF CUSTOMERS SERVED.] "Average 
 76.1   number of customers served" means the number of active, metered, 
 76.2   customer accounts available in a utility's 
 76.3   interruption-reporting database on the day that an interruption 
 76.4   occurs. 
 76.5      Subd. 3.  [CIRCUIT.] "Circuit" means a set of conductors 
 76.6   serving customer loads that are capable of being separated from 
 76.7   the serving substation automatically by a recloser, fuse, 
 76.8   sectionalizing equipment, and other devices. 
 76.9      Subd. 4.  [COMPONENT.] "Component" means a piece of 
 76.10  equipment, a line, a section of line, or a group of items that 
 76.11  is an entity for purposes of reporting, analyzing, and 
 76.12  predicting interruptions. 
 76.13     Subd. 5.  [CUSTOMER.] "Customer" means a contiguous 
 76.14  electrical service location, regardless of the number of meters 
 76.15  at the location. 
 76.16     Subd. 6.  [CUSTOMER INTERRUPTION.] "Customer interruption" 
 76.17  means the loss of service due to a forced outage for more than 
 76.18  five minutes, for one or more customers, which is the result of 
 76.19  one or more component failures. 
 76.20     Subd. 7.  [CUSTOMERS' INTERRUPTIONS CAUSED BY POWER 
 76.21  RESTORATION PROCESS.] "Customers' interruptions caused by power 
 76.22  restoration process" means when customers lose power as a result 
 76.23  of the process of restoring power.  The duration of these 
 76.24  outages is included in the customer-minutes of interruption.  
 76.25  Only the customers affected by the power restoration outages 
 76.26  that were not affected by the original outage are added to the 
 76.27  number of customer interruptions.  
 76.28     Subd. 8.  [CUSTOMER-MINUTES OF 
 76.29  INTERRUPTION.] "Customer-minutes of interruption" means the 
 76.30  number of minutes of forced outage duration multiplied by the 
 76.31  number of customers affected. 
 76.32     Subd. 9.  [ELECTRIC DISTRIBUTION LINE.] "Electric 
 76.33  distribution line" means circuits operating at less than 40,000 
 76.34  volts. 
 76.35     Subd. 10.  [FORCED OUTAGE.] "Forced outage" means an outage 
 76.36  that cannot be deferred. 
 77.1      Subd. 11.  [MAJOR CATASTROPHIC EVENTS.] "Major catastrophic 
 77.2   events" means events that are beyond the utility's control that 
 77.3   result in widespread system damages causing customer 
 77.4   interruptions that affect at least ten percent of the customers 
 77.5   in the system or in an operating area or that result in 
 77.6   customers being without electric service for durations of at 
 77.7   least 24 hours. 
 77.8      Subd. 12.  [MAJOR STORM.] "Major storm" means a period of 
 77.9   severe adverse weather resulting in widespread system damage 
 77.10  causing customer interruptions that affect at least ten percent 
 77.11  of the customers on the system or in an operating area or that 
 77.12  result in customers being without electric service for durations 
 77.13  of at least 24 hours. 
 77.14     Subd. 13.  [MOMENTARY INTERRUPTION.] "Momentary 
 77.15  interruption" means an interruption of electric service with a 
 77.16  duration shorter than the time necessary to be classified as a 
 77.17  customer interruption. 
 77.18     Subd. 14.  [OPERATING AREA.] "Operating area" means a 
 77.19  geographical subdivision of each electric utility's service 
 77.20  territory that functions under the direction of a company office 
 77.21  and may be used for reporting interruptions under this article.  
 77.22  These areas may also be referred to as regions, divisions, or 
 77.23  districts. 
 77.24     Subd. 15.  [OUTAGE.] "Outage" means the failure of a power 
 77.25  system component that results in one or more customer 
 77.26  interruptions. 
 77.27     Subd. 16.  [OUTAGE DURATION.] "Outage duration" means the 
 77.28  one minute or greater period from the initiation of an 
 77.29  interruption to a customer until service has been restored to 
 77.30  that customer. 
 77.31     Subd. 17.  [PARTIAL CIRCUIT OUTAGE CUSTOMER 
 77.32  COUNT.] "Partial circuit outage customer count" means when only 
 77.33  part of a circuit experiences an outage, the number of customers 
 77.34  affected is estimated, unless an actual count is available.  
 77.35  When power is partially restored, the number of customers 
 77.36  restored is also estimated.  Most utilities use estimates based 
 78.1   on the portion of the circuit restored. 
 78.2      Subd. 18.  [PLANNED OUTAGES.] "Planned outages" means those 
 78.3   outages scheduled by the utility. These interruptions are 
 78.4   sometimes necessary to connect new customers or perform 
 78.5   maintenance activities safely.  They must not be included in the 
 78.6   calculation of reliability indexes. 
 78.7      Subd. 19.  [RELIABILITY.] "Reliability" means the degree to 
 78.8   which electric service is supplied without interruption. 
 78.9      Subd. 20.  [RELIABILITY INDEXES.] "Reliability indexes" 
 78.10  include the following performance indices for measuring 
 78.11  frequency and duration of service interruptions: 
 78.12     (a) The system average interruption frequency index is the 
 78.13  average number of interruptions per customer per year.  It is 
 78.14  determined by dividing the total annual number of customer 
 78.15  interruptions by the average number of customers served during 
 78.16  the year. 
 78.17     (b) The system average interruption duration index is the 
 78.18  average customer-minutes of interruption per customer.  It is 
 78.19  determined by dividing the annual sum of customer-minutes of 
 78.20  interruption by the average number of customers served during 
 78.21  the year. 
 78.22     (c) The customer average interruption duration index is the 
 78.23  average customer-minutes of interruption per customer 
 78.24  interruption.  It approximates the average length of time 
 78.25  required to complete service restoration.  It is determined by 
 78.26  dividing the annual sum of all customer-minutes of interruption 
 78.27  durations by the annual number of customer interruptions. 
 78.28     Sec. 2.  [216B.82] [RECORDING SERVICE INTERRUPTION 
 78.29  INDEXES.] 
 78.30     Subdivision 1.  [SYSTEM INTERRUPTION DATA.] Each electric 
 78.31  utility with 6,000 retail customers or more shall keep a record 
 78.32  of the necessary interruption data and calculate the system 
 78.33  average interruption frequency index, system average 
 78.34  interruption duration index, and customer average interruption 
 78.35  duration index of its system, and of each operating area, if 
 78.36  applicable, at the end of each calendar year for the previous 
 79.1   12-month period. 
 79.2      Subd. 2.  [CIRCUIT INTERRUPTION DATA.] Unless a utility 
 79.3   uses alternative criteria as provided in section 216B.83, 
 79.4   subdivision 2, paragraph (d), each utility also shall, at the 
 79.5   end of each calendar year, calculate the system average 
 79.6   interruption frequency index, system average interruption 
 79.7   duration index, and customer average interruption duration index 
 79.8   for each circuit in each operating area.  Each circuit in each 
 79.9   operating area must then be listed in order separately according 
 79.10  to its system average interruption frequency index, its system 
 79.11  average interruption duration index, and its customer average 
 79.12  interruption duration index, beginning with the highest values 
 79.13  for each index. 
 79.14     Sec. 3.  [216B.83] [ANNUAL REPORT.] 
 79.15     Subdivision 1.  [SUMMARY REPORT GENERALLY.] Beginning on 
 79.16  July 1, 2002, and by July 1 of every year thereafter, each 
 79.17  electric utility with 6,000 retail customers or more shall file 
 79.18  with the commission, or in the case of a cooperative electric 
 79.19  association or municipal utility, with the local governing body 
 79.20  of the utility or association a report summarizing various 
 79.21  measures of reliability.  The form of the report is subject to 
 79.22  review and comment by the commission staff.  Names and numbers 
 79.23  used to identify operating areas or individual circuits may 
 79.24  conform to the utility's practice, but should allow ready 
 79.25  identification of the geographic location or the general area 
 79.26  served.  Electronic recording and reporting of the required data 
 79.27  and information is encouraged.  
 79.28     Subd. 2.  [INFORMATION REQUIRED.] (a) The report must 
 79.29  include at least the information described in paragraphs (b) to 
 79.30  (h). 
 79.31     (b) The report must provide an overall assessment of the 
 79.32  reliability of performance including the aggregate system 
 79.33  average interruption frequency index, system average 
 79.34  interruption duration index, and customer average interruption 
 79.35  duration index by system and each operating area, as applicable. 
 79.36     (c) The report must include a list of the worst performing 
 80.1   circuits based on system average interruption frequency index, 
 80.2   system average interruption duration index, and customer average 
 80.3   interruption duration index for the calendar year.  This portion 
 80.4   of the report must describe the actions that the utility has 
 80.5   taken or will take to remedy the conditions responsible for each 
 80.6   listed circuit's unacceptable performance.  The actions taken or 
 80.7   planned should be briefly described.  Target dates for 
 80.8   corrective actions must be included in the report.  When the 
 80.9   utility determines that actions on its part are unwarranted, its 
 80.10  report shall provide adequate justification for that conclusion. 
 80.11     (d) Utilities that use or prefer alternative criteria for 
 80.12  measuring individual circuit performance to those described in 
 80.13  paragraphs (b) and (c) and that are required by this section to 
 80.14  submit an annual report of reliability data, shall submit their 
 80.15  alternative listing of circuits along with the criteria used to 
 80.16  rank circuit performance. 
 80.17     (e) Information must be included with respect to any report 
 80.18  on the accomplishment of the improvements proposed in prior 
 80.19  reports for which completion has not been previously reported. 
 80.20     (f) The report must describe any new reliability or power 
 80.21  quality programs and changes that are made to existing programs. 
 80.22     (g) It must include a status report of any long-range 
 80.23  electric distribution plans. 
 80.24     (h) In addition to the information included in paragraph 
 80.25  (b), each utility that has the technical capability and 
 80.26  administrative resources shall report the following additional 
 80.27  service quality information: 
 80.28     (1) route miles of electric distribution line reconstructed 
 80.29  during the year, with separate totals for single- and 
 80.30  three-phase circuits provided; 
 80.31     (2) total route miles of electric distribution line in 
 80.32  service at year's end, segregated by voltage level; 
 80.33     (3) monthly average speed of answer for telephone calls 
 80.34  received regarding emergencies; 
 80.35     (4) the average number of calendar days a utility takes to 
 80.36  install and energize service to a customer site once it is ready 
 81.1   to receive service, with a separate average calculated for each 
 81.2   month, including all extensions energized during the calendar 
 81.3   month; 
 81.4      (5) the total number of written and telephone customer 
 81.5   complaints received in the areas of safety, outages, power 
 81.6   quality, customer property damage, and other areas, by month 
 81.7   filed; 
 81.8      (6) total annual tree-trimming budget and actual expenses; 
 81.9   and 
 81.10     (7) total annual projected and actual miles of tree-trimmed 
 81.11  distribution line. 
 81.12     Sec. 4.  [216B.84] [INITIAL HISTORICAL RELIABILITY 
 81.13  PERFORMANCE REPORT.] 
 81.14     (a) Each electric utility with 6,000 retail customers or 
 81.15  more that has historically used measures of system, operating 
 81.16  area, and circuit reliability performance shall initially submit 
 81.17  annual system average interruption frequency index, system 
 81.18  average interruption duration index, and customer average 
 81.19  interruption duration index data for the previous three years.  
 81.20  Those utilities that have this data for some time period less 
 81.21  than three years shall submit data for those years it is 
 81.22  available. 
 81.23     (b) Those utilities whose historical reliability 
 81.24  performance data is similar or related to those measures listed 
 81.25  in paragraph (a), but differs due to how the parameters are 
 81.26  defined or calculated, shall submit the data it has and explain 
 81.27  any material differences from the prescribed indices.  After the 
 81.28  effective date of this section, utilities shall modify their 
 81.29  reliability performance measures to conform to those specified 
 81.30  in sections 216B.80 to 216B.86 for purposes of consistent 
 81.31  reporting of comparable data in the future. 
 81.32     Sec. 5.  [216B.85] [INTERRUPTIONS OF SERVICE; RECORDS; 
 81.33  NOTICE.] 
 81.34     Subdivision 1.  [RECORDS.] (a) Each utility shall keep 
 81.35  records of all interruptions to service affecting the entire 
 81.36  distribution system of any single community or an important 
 82.1   division of a community, and include in the records each 
 82.2   interruption's location, date and time, and duration; the 
 82.3   approximate number of customers affected; the circuit or 
 82.4   circuits involved; and, when known, the cause of each 
 82.5   interruption. 
 82.6      (b) When complete distribution systems or portions of 
 82.7   communities have service furnished from unattended stations, 
 82.8   these records must be kept to the extent practicable.  The 
 82.9   record of unattended stations shall show interruptions that 
 82.10  require attention to restore service, with the estimated time of 
 82.11  interruption.  Breaker or fuse operations affecting service 
 82.12  should also be indicated even though duration of interruption 
 82.13  may not be known. 
 82.14     Subd. 2.  [NOTICE OF INTERRUPTIONS OF BULK POWER SUPPLY 
 82.15  FACILITIES.] (a) Each utility owning or operating bulk power 
 82.16  supply facilities shall record any event described in clauses 
 82.17  (1) to (5) involving any generating unit or electric facilities 
 82.18  operating at a nominal voltage of 69 kilovolts or higher, and 
 82.19  shall make such records available to the commission 
 82.20  semi-annually or upon request of the commission: 
 82.21     (1) any interruption or loss of service to customers for 15 
 82.22  minutes or more to aggregate firm loads in excess of 200,000 
 82.23  kilowatts; 
 82.24     (2) any interruption or loss of service to customers for 15 
 82.25  minutes or more to aggregate firm loads exceeding the lesser of 
 82.26  100,000 kilowatts or one-half of the current annual system peak 
 82.27  load and not required recorded under clause (1); 
 82.28     (3) any decision to issue a public request for reduction in 
 82.29  use of electricity; 
 82.30     (4) an action to reduce firm customer loads by reduction of 
 82.31  voltage for reasons of maintaining adequacy of bulk electric 
 82.32  power supply; and 
 82.33     (5) any action to reduce firm customer loads by manual 
 82.34  switching, operation of automatic load-shedding devices, or any 
 82.35  other means for reasons of maintaining adequacy of bulk electric 
 82.36  power supply.  
 83.1      Subd. 3.  [NOTICE OF OTHER INTERRUPTIONS OF POWER.] Each 
 83.2   utility shall record service interruptions of 60 minutes or more 
 83.3   to an entire distribution substation bus or entire feeder 
 83.4   serving either 500 or more customers or entire cities or 
 83.5   villages having 200 or more customers.  
 83.6      Subd. 4.  [INFORMATION REQUIRED.] The written records 
 83.7   required in subdivisions 2 and 3 must include the date, time, 
 83.8   duration, general location, approximate number of customers 
 83.9   affected, identification of circuit or circuits involved, and, 
 83.10  when known, the cause of the interruption.  When extensive 
 83.11  interruptions occur, as from a storm, a narrative record 
 83.12  including the extent of the interruptions and system damage, 
 83.13  estimated number of customers affected, and a list of entire 
 83.14  communities interrupted may be recorded in lieu of records of 
 83.15  individual interruptions.  When customer service interruptions 
 83.16  are necessary, the utility shall make reasonable efforts to 
 83.17  notify affected customers in advance.  
 83.18     Sec. 6.  [216B.86] [CUSTOMERS' COMPLAINTS.] 
 83.19     Each utility shall keep a record of complaints received by 
 83.20  it from its customers in regard to safety or service, and the 
 83.21  operation of its system, with appropriate response times 
 83.22  designated for critical safety and monetary loss situations and 
 83.23  shall investigate if appropriate.  The record must show the name 
 83.24  and address of the complainant, the date and nature of the 
 83.25  complaint, the priority assigned to the assistance, and its 
 83.26  disposition and the time and date of its disposition. 
 83.27     Sec. 7.  [216B.87] [STANDARDS FOR DISTRIBUTION UTILITIES.] 
 83.28     (a) The commission and each cooperative electric 
 83.29  association and municipal utility shall adopt standards for 
 83.30  safety, reliability, and service quality for distribution 
 83.31  utilities.  Standards for cooperative electric associations and 
 83.32  municipal utilities should be as consistent as possible with the 
 83.33  commission standards. 
 83.34     (b) Reliability standards must be based on the system 
 83.35  average interruption frequency index, system average 
 83.36  interruption duration index, and customer average interruption 
 84.1   duration index measurement indices.  Service quality standards 
 84.2   must specify, if technically and administratively feasible: 
 84.3      (1) average call center response time; 
 84.4      (2) customer disconnection rate; 
 84.5      (3) meter-reading frequency; 
 84.6      (4) complaint resolution response time; and 
 84.7      (5) service extension request response time. 
 84.8      (c) Minimum performance standards developed under this 
 84.9   section must treat similarly situated distribution systems 
 84.10  similarly and recognize differing characteristics of system 
 84.11  design and hardware. 
 84.12     (d) Electric distribution utilities shall comply with all 
 84.13  applicable governmental and industry standards required for the 
 84.14  safety, design, construction and operation of electric 
 84.15  distribution facilities, including section 326.243.