SF 722

as introduced - 82nd Legislature (2001 - 2002) Posted on 12/15/2009 12:00am

  1.1                          A bill for an act 
  1.2             relating to energy; establishing a state energy plan 
  1.3             and promoting energy conservation; making conforming, 
  1.4             technical, and clarifying changes; amending Minnesota 
  1.5             Statutes 2000, sections 116C.691, subdivision 2, and 
  1.6             by adding a subdivision; 116C.692; 116C.779; 216A.07, 
  1.7             by adding a subdivision; 216B.16, subdivision 6b; 
  1.8             216B.1621, subdivision 2; 216B.164, subdivisions 3, 4, 
  1.9             and 6; 216B.241, subdivisions 1, 1a, 1b, 1c, 2, and 
  1.10            2b; 216B.2421, subdivision 1; 216B.2423, subdivision 
  1.11            2; 216B.243, subdivision 3; 216C.17, subdivision 3; 
  1.12            and 216C.41, subdivisions 1, 3, 4, 5, and by adding a 
  1.13            subdivision; proposing coding for new law in Minnesota 
  1.14            Statutes, chapters 216B; and 272; proposing coding for 
  1.15            new law as Minnesota Statutes, chapter 216E; repealing 
  1.16            Minnesota Statutes 2000, sections 216B.241, 
  1.17            subdivision 2a; 216B.2422, subdivisions 1, 2, 2a, 4, 
  1.18            5, and 6; and 216C.18. 
  1.19  BE IT ENACTED BY THE LEGISLATURE OF THE STATE OF MINNESOTA: 
  1.20                             ARTICLE 1
  1.21                         STATE ENERGY PLAN
  1.22     Section 1.  [216E.01] [DEFINITIONS.] 
  1.23     Subdivision 1.  [SCOPE.] The terms used in this chapter 
  1.24  have the meanings given them in this section.  If not defined in 
  1.25  this section, those terms defined in chapters 216A, 216B, and 
  1.26  216C also apply to terms used in this chapter. 
  1.27     Subd. 2.  [BIOMASS.] "Biomass" means herbaceous crops, 
  1.28  trees, agricultural waste, and aquatic plant matter used to 
  1.29  generate electric energy, but excludes mixed municipal solid 
  1.30  waste as defined in section 115A.03. 
  1.31     Subd. 3.  [COMMISSION.] "Commission" means the public 
  1.32  utilities commission. 
  2.1      Subd. 4.  [COMMISSIONER.] "Commissioner" means the 
  2.2   commissioner of commerce. 
  2.3      Subd. 5.  [DEPARTMENT.] "Department" means the department 
  2.4   of commerce. 
  2.5      Subd. 6.  [ELECTRIC UTILITY.] "Electric utility" means an 
  2.6   entity that provides 250,000 kilowatt hours annually to retail 
  2.7   customers in the state, or that owns or operates an electric 
  2.8   transmission facility in the state. 
  2.9      Subd. 7.  [ENERGY.] "Energy" means natural gas, 
  2.10  electricity, and petroleum products. 
  2.11     Subd. 8.  [ENERGY CONSERVATION.] "Energy conservation" 
  2.12  means demand-side management of energy supplies and includes 
  2.13  activities that demonstrably reduce present and future demand 
  2.14  for energy or that result in more efficient use of the same 
  2.15  amount of energy. 
  2.16     Subd. 9.  [LOW-HEAD HYDROPOWER.] "Low-head hydropower" 
  2.17  means a hydropower facility that has a head of less than 66 feet.
  2.18     Subd. 10.  [WIND ENERGY CONVERSION SYSTEM.] "Wind energy 
  2.19  conversion system" or "WECS" means any device, such as a wind 
  2.20  charger, windmill, or wind turbine and associated facilities 
  2.21  that converts wind energy to electrical energy. 
  2.22     Sec. 2.  [216E.02] [ENERGY PLAN.] 
  2.23     The commissioner shall submit to the commission a proposed 
  2.24  energy plan by March 1, 2002, and every four years thereafter.  
  2.25  The plan must: 
  2.26     (1) identify important trends and issues in energy supply, 
  2.27  consumption, conservation, and costs; 
  2.28     (2) set energy goals; and 
  2.29     (3) develop strategies to meet the goals. 
  2.30     Sec. 3.  [216E.03] [ENERGY PLAN CONTENTS.] 
  2.31     (a) The energy plan must include: 
  2.32     (1) the amount and type of projected statewide energy 
  2.33  consumption over the next ten years; 
  2.34     (2) a determination of whether and the extent to which 
  2.35  existing and anticipated energy production and transportation 
  2.36  facilities will or will not be able to supply needed energy; 
  3.1      (3) a determination of the potential for conservation to 
  3.2   meet some or all of the projected need for energy; and 
  3.3      (4) an assessment of the environmental impact of projected 
  3.4   energy consumption over the next ten years, determined by the 
  3.5   commissioner in consultation with other state agencies and other 
  3.6   interested persons, prepared by the commissioner of the 
  3.7   pollution control agency, with strategies to mitigate those 
  3.8   impacts. 
  3.9      (b) In addition, the plan must include an analysis of the 
  3.10  technical and economic feasibility of meeting future electric 
  3.11  energy needs in the state by use of environmentally and 
  3.12  economically sustainable electric generation.  This analysis 
  3.13  must discuss: 
  3.14     (1) capacity needs; 
  3.15     (2) maximum reasonably feasible energy conservation; 
  3.16     (3) achievable generation and distribution efficiencies; 
  3.17     (4) the potential role of renewable and sustainable forms 
  3.18  of energy and general cost projections; 
  3.19     (5) the costs associated with less environmentally damaging 
  3.20  sources of electric energy; 
  3.21     (6) the need for changes in transmission capability to 
  3.22  deliver electricity to consumers; 
  3.23     (7) whether and to what extent more distributed generation 
  3.24  can lessen the need for long distance transmission of power; 
  3.25     (8) the costs, benefits, and future economic impact of 
  3.26  importing energy into the state and of exporting energy 
  3.27  generated in the state; 
  3.28     (9) the costs and benefits of immediate investment in 
  3.29  renewable energy sources and modern energy technology; and 
  3.30     (10) the potential for additional streamlining of state and 
  3.31  local procedures for siting, permitting, and constructing energy 
  3.32  facilities. 
  3.33     Sec. 4.  [216E.04] [ENERGY GOALS.] 
  3.34     (a) The plan must establish statewide goals and list 
  3.35  strategies to accomplish the following goals for: 
  3.36     (1) energy conservation; 
  4.1      (2) limiting adverse environmental emissions from the 
  4.2   generation of electric energy consumed in the state; 
  4.3      (3) production of electric energy consumed in the state 
  4.4   from renewable energy sources; 
  4.5      (4) deployment of distributed electric generation 
  4.6   technologies; and 
  4.7      (5) ensuring that energy service is affordable and 
  4.8   available to all consumers in the state. 
  4.9      (b) In addition, the plan must: 
  4.10     (1) identify electric transmission inadequacies and 
  4.11  alternative means of addressing those inadequacies; 
  4.12     (2) identify geographic areas that contain critical habitat 
  4.13  or are in bird migratory pathways and that, therefore, are not 
  4.14  desirable locations for wind energy conversion systems (WECS); 
  4.15  and 
  4.16     (3) set technical standards for WECS installations of five 
  4.17  megawatts through 30 megawatts nameplate capacity. 
  4.18     (c) The goals adopted in the plan may be one-time goals or 
  4.19  a series of goals to meet overall objectives. 
  4.20     Sec. 5.  [216E.05] [ENERGY POLICY GUIDELINES.] 
  4.21     (a) In setting energy policy goals under section 216E.03, 
  4.22  the highest priority is energy conservation.  The following 
  4.23  electric energy sources are listed in their descending order of 
  4.24  preference: 
  4.25     (1) wind and solar; 
  4.26     (2) biomass and low-head or refurbished hydropower; 
  4.27     (3) decomposition gases produced by solid waste management 
  4.28  facilities, natural gas-fired cogeneration, and waste materials 
  4.29  or byproducts combined with natural gas; 
  4.30     (4) natural gas, hydropower that is not low-head or 
  4.31  refurbished hydropower, and solid waste as a direct fuel or 
  4.32  refuse-derived fuel; and 
  4.33     (5) coal and nuclear power. 
  4.34     (b) In paragraph (a), clauses (3) and (4), use of waste 
  4.35  materials must be limited to those waste materials and 
  4.36  byproducts necessarily generated or produced by efficient 
  5.1   processes and systems.  Prevention or minimizing waste and 
  5.2   byproducts are preferred over relying on continued generation of 
  5.3   waste materials and byproducts.  Within each clause in paragraph 
  5.4   (a), the more efficient technology that generates electric 
  5.5   energy, particularly a technology that captures and reuses waste 
  5.6   heat, is preferred over other technologies listed in each clause 
  5.7   of paragraph (a). 
  5.8      Sec. 6.  [216E.06] [PLAN DEVELOPMENT AND APPROVAL.] 
  5.9      Subdivision 1.  [CONSULTATION.] In preparing the proposed 
  5.10  energy plan, the commissioner shall consult with: 
  5.11     (1) the commissioners of agriculture, economic security, 
  5.12  health, natural resources, and the pollution control agency; 
  5.13     (2) the office of strategic and long-range planning; 
  5.14     (3) academic and other energy planning experts; 
  5.15     (4) regional energy infrastructure planning groups; 
  5.16     (5) energy utilities and other energy service providers; 
  5.17     (6) public interest advocacy groups; and 
  5.18     (7) other interested persons. 
  5.19     Subd. 2.  [PUBLIC PARTICIPATION.] The commissioner shall: 
  5.20     (1) invite public comment and participation during plan 
  5.21  development; 
  5.22     (2) hold at least one public meeting on the proposed plan 
  5.23  in each energy infrastructure planning region of the state after 
  5.24  at least 30 days public notice in the region; and 
  5.25     (3) provide participant assistance by making assessments in 
  5.26  addition to biennial appropriations under section 216B.62.  
  5.27  Participant assistance is limited to $10,000 per participant and 
  5.28  a total of $200,000 in each four-year planning cycle.  The 
  5.29  commissioner must find that a person or group that requests 
  5.30  assistance can materially assist in developing the plan and 
  5.31  likely would not be able to participate effectively without the 
  5.32  assistance. 
  5.33     Subd. 3.  [INFORMATION.] To develop the initial plan, the 
  5.34  commissioner shall rely on information in the most recent 
  5.35  integrated resource plan approved by the public utilities 
  5.36  commission for each energy utility or, in the case of a 
  6.1   municipal utility or a cooperative electric association, filed 
  6.2   with the commission.  For future proposed plans, the 
  6.3   commissioner shall rely on information contained in energy 
  6.4   utility compliance plans and progress reports.  Each energy 
  6.5   utility or energy service provider in the state shall comply 
  6.6   with additional requests for information that the commissioner 
  6.7   deems necessary to complete the proposed plan.  In addition, the 
  6.8   commissioner shall gather information from any other relevant 
  6.9   sources, including, but not limited to, regional and national 
  6.10  reliability organizations, regional and national transmission 
  6.11  organizations, regional energy infrastructure planning groups, 
  6.12  energy trade associations, and energy research entities. 
  6.13     Subd. 4.  [NOTICE AND COMMENT; PLAN APPROVAL.] The public 
  6.14  utilities commission shall approve, or approve with 
  6.15  modifications, the energy plan by September 1, 2002, and every 
  6.16  four years thereafter.  The commission shall provide public 
  6.17  notice of any meetings to discuss the proposed plan and allow 
  6.18  opportunity for written comment prior to making its decision.  
  6.19  The commission shall publish in the State Register its order 
  6.20  approving the final energy plan. 
  6.21     Sec. 7.  [216E.07] [REGIONAL ENERGY INFRASTRUCTURE 
  6.22  PLANNING.] 
  6.23     Subdivision 1.  [ESTABLISHING PLANNING REGIONS.] The 
  6.24  commission, after notice and opportunity for written comment, 
  6.25  shall establish geographic regional energy infrastructure 
  6.26  planning regions in the state by October 1, 2001.  Planning 
  6.27  regions shall coincide, if feasible, with existing subregional 
  6.28  planning areas used by the regional electric reliability or 
  6.29  regional transmission organization serving Minnesota. 
  6.30     Subd. 2.  [PLANNING GROUP.] Each energy utility that 
  6.31  operates in an identified region shall participate in the 
  6.32  regional energy infrastructure planning group.  Each regional 
  6.33  group must include as voting members, at a minimum, 
  6.34  representatives of energy utilities, public interest groups, and 
  6.35  local governments. 
  6.36     Subd. 3.  [PUBLIC MEETINGS.] Each regional energy 
  7.1   infrastructure planning group shall hold public meetings within 
  7.2   the region on a regular basis and provide public notice at least 
  7.3   14 calendar days in advance of a meeting. 
  7.4      Subd. 4.  [REPORT.] By December 31, 2001, and every two 
  7.5   years thereafter, each regional energy infrastructure planning 
  7.6   group shall submit a report to the commission and the department 
  7.7   that: 
  7.8      (1) identifies inadequacies in electric generation and 
  7.9   transmission within the region; 
  7.10     (2) lists alternative ways to address identified 
  7.11  inadequacies in priority order consistent with the guidelines in 
  7.12  section 216E.05 and, for reports in years after 2001, the 
  7.13  existing statewide energy plan approved by the commission under 
  7.14  section 216E.06, subdivision 4; and 
  7.15     (3) identifies potential general and, to the extent known, 
  7.16  specific economic, environmental, and social issues associated 
  7.17  with each alternative. 
  7.18     Sec. 8.  [216E.08] [ELECTRIC UTILITY COMPLIANCE PLANS.] 
  7.19     Subdivision 1.  [COMPLIANCE PLAN FILING.] By March 15, 
  7.20  2003, and every four years thereafter, each electric utility 
  7.21  shall file with the commission a plan that identifies how the 
  7.22  utility will comply with the goals of the statewide energy plan 
  7.23  and meet the energy needs of its customers.  Each compliance 
  7.24  plan must: 
  7.25     (1) describe in summary form the utility's existing energy 
  7.26  resources and transmission and delivery system; 
  7.27     (2) forecast the electric energy needs of the electric 
  7.28  utility's customers over the next ten years; 
  7.29     (3) identify deficiencies in the utility's energy resources 
  7.30  and transmission and distribution capacity to meet the needs of 
  7.31  its customers over the ten-year period; 
  7.32     (4) propose projects to meet the identified deficiencies 
  7.33  that are consistent with the statewide energy plan, goals, and 
  7.34  guidelines under sections 216E.01 to 216E.06; 
  7.35     (5) explain how the energy utility utilized the regional 
  7.36  energy infrastructure planning group process to arrive at its 
  8.1   deficiency determinations and project proposals and how, and to 
  8.2   what extent, the utility sought and considered public 
  8.3   participation in making its determinations and proposals; 
  8.4      (6) how the proposed projects provide the most reasonably 
  8.5   minimal adverse environmental and social impacts for the most 
  8.6   reasonably minimal costs, utilizing environmental and 
  8.7   socioeconomic cost values established by the commission and 
  8.8   other relevant data and information; and 
  8.9      (7) for compliance plans subsequent to the first one, 
  8.10  report on progress made in implementing its previous compliance 
  8.11  plan. 
  8.12     Subd. 2.  [JOINT PLANS.] A generation and transmission 
  8.13  organization or any other organization or group may submit a 
  8.14  compliance plan on behalf of one or more municipal or rural 
  8.15  electric cooperative utilities.  One or more public utilities 
  8.16  may submit a joint compliance plan. 
  8.17     Sec. 9.  [216E.09] [COMPLIANCE PLAN REVIEW.] 
  8.18     Subdivision 1.  [COMMISSION REVIEW AND DECISION.] The 
  8.19  commission shall review an electric utility's compliance plan, 
  8.20  after providing notice and opportunity for written comment.  
  8.21  Within 120 days of receipt of a plan, the commission shall 
  8.22  approve it if it meets the standards in subdivision 2 or, if it 
  8.23  does not meet the standards, the commission shall: 
  8.24     (1) for a plan submitted by a municipal or rural electric 
  8.25  cooperative utility, refer the compliance plan back to the 
  8.26  governing board of the utility; or 
  8.27     (2) for a plan submitted by a public utility or other 
  8.28  entity, modify or reject the plan and require resubmission of a 
  8.29  plan that complies with the standards. 
  8.30     Subd. 2.  [COMMISSION REVIEW STANDARDS.] The public 
  8.31  utilities commission shall consider whether the electric utility 
  8.32  has demonstrated that: 
  8.33     (1) sufficient public input was incorporated into the 
  8.34  planning process; 
  8.35     (2) if the electric utility implements the plan, it will 
  8.36  comply with the energy plan approved under section 216E.06; and 
  9.1      (3) if the utility implements the plan, it will meet the 
  9.2   energy needs of the utility's customers in an economically and 
  9.3   environmentally sound and sustainable manner. 
  9.4      Sec. 10.  [216E.10] [DEMONSTRATING PLAN PROGRESS.] 
  9.5      By March 1, 2005, and every four years thereafter, each 
  9.6   electric utility shall provide the commission and the department 
  9.7   an interim report that identifies progress it has made to 
  9.8   implement its most recently approved compliance plan, problems 
  9.9   that have arisen, barriers to implementation, and any necessary 
  9.10  proposals to modify its compliance plan.  If the report proposes 
  9.11  to modify the compliance plan, the commission shall follow the 
  9.12  procedures and standards in section 216E.09. 
  9.13     Sec. 11.  [216E.11] [DEFICIENCY.] 
  9.14     Subdivision 1.  [DEFINITION.] "Deficiency" means a 
  9.15  condition, or set of conditions, that materially limit the 
  9.16  adequacy of electric supply, efficiency of electric service, or 
  9.17  reliability of electric service to an electric utility's 
  9.18  customers in the state that may require construction of a 
  9.19  generation or transmission project. 
  9.20     Subd. 2.  [NOTICE.] (a) An electric utility that identifies 
  9.21  a deficiency shall give notice of the deficiency to at least: 
  9.22     (1) the members of affected regional energy infrastructure 
  9.23  planning groups; 
  9.24     (2) any potentially affected landowners; and 
  9.25     (3) other interested persons, including officials of 
  9.26  potentially affected local governments. 
  9.27     (b) Notice of deficiency must be made before submitting a 
  9.28  request for approval of an energy project to any governmental 
  9.29  entity.  The energy utility may identify a deficiency as part of 
  9.30  a compliance plan, a progress report, or independently of either 
  9.31  and may submit a compliance plan or progress report as notice of 
  9.32  the deficiency as long as the deficiency and its implications 
  9.33  are clearly noted in a summary preceding the body of the 
  9.34  document. 
  9.35     Sec. 12.  [216E.12] [PUBLIC PURPOSE ENERGY PROJECTS.] 
  9.36     Subdivision 1.  [LIST.] The commission shall maintain a 
 10.1   list of public purpose energy projects.  Projects qualify for 
 10.2   the list upon approval by the commission under subdivision 4, 
 10.3   except a wind energy conversion system with a combined nameplate 
 10.4   capacity of 30 megawatts or less is a public purpose project if 
 10.5   it meets the requirements of subdivision 6. 
 10.6      Subd. 2.  [BENEFITS.] (a) Notwithstanding any other law to 
 10.7   the contrary, eminent domain powers may be used for an energy 
 10.8   project only if it is on the public purpose energy projects list.
 10.9      (b) In siting and routing a public purpose project, the 
 10.10  environmental quality board and any permitting entity may not 
 10.11  consider the "no build" alternative in environmental review or 
 10.12  in evaluating and considering permits under section 116D.04, 
 10.13  subdivision 6. 
 10.14     (c) A public purpose project is exempt from the certificate 
 10.15  of need requirement in section 216B.243. 
 10.16     (d) A public purpose project is eligible for reasonable 
 10.17  accelerated depreciation to be determined by the commission. 
 10.18     Subd. 3.  [DEFICIENCY CERTIFICATION; PUBLIC PURPOSE ENERGY 
 10.19  PROJECT.] (a) A person who desires to place a proposed energy 
 10.20  project on the public purpose energy project list shall file 
 10.21  with the commission, the department, and any relevant regional 
 10.22  energy infrastructure planning group, an application for 
 10.23  certification of the deficiency the project is designed to 
 10.24  address and, at the same time or a later time, a request to add 
 10.25  the proposed project to the list.  If the request is solely to 
 10.26  certify a deficiency, the commission shall do so unless: 
 10.27     (1) the alleged deficiency has not been identified in the 
 10.28  statewide energy plan, an electric utility compliance plan or 
 10.29  progress report, or a regional energy infrastructure planning 
 10.30  group report; 
 10.31     (2) is inconsistent with any plan or report; or 
 10.32     (3) is not supported by evidence submitted with the request.
 10.33     (b) The commission shall make a determination to accept, 
 10.34  modify, or reject certification of a deficiency within 60 days 
 10.35  of a filing, unless another party challenges the deficiency, in 
 10.36  which case the commission shall establish an expedited contested 
 11.1   issue procedure not to exceed 120 days. 
 11.2      Subd. 4.  [PUBLIC PURPOSE PROJECT CRITERIA.] The electric 
 11.3   utility shall demonstrate that a project is a public purpose 
 11.4   project.  The commission may find that a project is a public 
 11.5   purpose project only if the project addresses a certifiable or 
 11.6   previously certified deficiency and is consistent with the 
 11.7   energy policy plan approved under section 216E.06.  The 
 11.8   commission may not place a project on the list if a project that 
 11.9   is preferred to the proposed project under section 216E.05 is 
 11.10  shown by any person to be reasonably feasible and comparably 
 11.11  economic. 
 11.12     Subd. 5.  [DESIGNATING PUBLIC PURPOSE PROJECTS.] (a) The 
 11.13  commission shall decide whether a project is a public purpose 
 11.14  project within 120 days of application by an electric utility.  
 11.15  The commission shall provide notice and an opportunity for 
 11.16  written comment.  Any relevant regional energy infrastructure 
 11.17  planning group shall comment on alternatives available to 
 11.18  address the deficiency and recommend whether to place the 
 11.19  project on the list within 90 days of the date the application 
 11.20  was filed.  Failure of a planning group to comment neither 
 11.21  supports nor opposes the listing of the project. 
 11.22     (b) The commission may provide participant assistance by 
 11.23  making additional assessments under section 216B.62.  
 11.24  Participant assistance is limited to $10,000 per participant and 
 11.25  a total of $50,000 per proceeding.  The commissioner must find 
 11.26  that a person or group that requests assistance can materially 
 11.27  assist the commission in making a determination and likely would 
 11.28  not be able to participate effectively without the assistance. 
 11.29     Subd. 6.  [PUBLIC PURPOSE WECS.] (a) A wind energy 
 11.30  conversion system (WECS) with a combined nameplate capacity of 
 11.31  30 megawatts or less is a public purpose energy project if: 
 11.32     (1) it is not proposed to be located in an area identified 
 11.33  in the energy plan adopted under section 216E.06 as containing 
 11.34  critical habitat or in a bird migratory pathway; and 
 11.35     (2) the project proposer notifies the commission, the 
 11.36  commissioners of commerce and natural resources, and the 
 12.1   environmental quality board of the proposed project and has not 
 12.2   received a written objection to the project within 45 days of 
 12.3   delivery of the notice.  An objection must be sent to the 
 12.4   project proposer and all other state agencies listed above. 
 12.5      (b) If a written objection is made to a proposed WECS 
 12.6   project, the procedure in subdivision 5 applies to determine 
 12.7   whether the proposed project qualifies for the public purpose 
 12.8   projects list. 
 12.9      (c) Placement of a WECS with a combined nameplate capacity 
 12.10  of 30 megawatts or less on the public purpose energy projects 
 12.11  list supersedes and preempts all other state permitting 
 12.12  processes and all zoning, building, or land use rules, 
 12.13  regulations, or ordinances adopted by regional, county, local, 
 12.14  and special purpose governments.  
 12.15     Sec. 13.  [REPEALER.] 
 12.16     Minnesota Statutes 2000, sections 216B.2422, subdivisions 
 12.17  1, 2, 2a, 4, 5, and 6; and 216C.18, are repealed. 
 12.18                             ARTICLE 2 
 12.19                        ENERGY CONSERVATION 
 12.20     Section 1.  Minnesota Statutes 2000, section 216B.241, 
 12.21  subdivision 1, is amended to read: 
 12.22     Subdivision 1.  [DEFINITIONS.] For purposes of this section 
 12.23  and section 216B.16, subdivision 6b, the terms defined in this 
 12.24  subdivision have the meanings given them.  
 12.25     (a) "Commission" means the public utilities commission. 
 12.26     (b) "Commissioner" means the commissioner of public service 
 12.27  commerce. 
 12.28     (c) "Customer facility" means all buildings, structures, 
 12.29  equipment, and installations at a single site. 
 12.30     (d) "Department" means the department of public 
 12.31  service commerce. 
 12.32     (e) "Energy conservation" means demand-side management of 
 12.33  energy supplies and includes activities that demonstrably reduce 
 12.34  present and future demand for energy or that result in more 
 12.35  efficient use of the same amount of energy.  Load management 
 12.36  that does not reduce actual overall energy demand is not energy 
 13.1   conservation. 
 13.2      (f) "Energy conservation improvement" means the purchase or 
 13.3   installation of a device, method, material, or project that: 
 13.4      (1) reduces consumption of or increases efficiency in the 
 13.5   use of electricity or natural gas, including but not limited to 
 13.6   insulation and ventilation, storm or thermal doors or windows, 
 13.7   caulking and weatherstripping, furnace efficiency modifications, 
 13.8   thermostat or lighting controls, awnings, or systems to turn off 
 13.9   or vary the delivery of energy; a tangible or intangible 
 13.10  improvement that results in energy conservation. 
 13.11     (2) creates, converts, or actively uses energy from 
 13.12  renewable sources such as solar, wind, and biomass, provided 
 13.13  that the device or method conforms with national or state 
 13.14  performance and quality standards whenever applicable; 
 13.15     (3) seeks to provide energy savings through reclamation or 
 13.16  recycling and that is used as part of the infrastructure of an 
 13.17  electric generation, transmission, or distribution system within 
 13.18  the state or a natural gas distribution system within the state; 
 13.19  or 
 13.20     (4) provides research or development of new means of 
 13.21  increasing energy efficiency or conserving energy or research or 
 13.22  development of improvement of existing means of increasing 
 13.23  energy efficiency or conserving energy.  
 13.24     (f) (g) "Investments and expenses of a public utility" 
 13.25  includes the investments and expenses incurred by a public 
 13.26  utility in connection with an energy conservation improvement, 
 13.27  including but not limited to:  
 13.28     (1) the differential in interest cost between the market 
 13.29  rate and the rate charged on a no-interest or below-market 
 13.30  interest loan made by a public utility to a customer for the 
 13.31  purchase or installation of an energy conservation improvement; 
 13.32     (2) the difference between the utility's cost of purchase 
 13.33  or installation of energy conservation improvements and any 
 13.34  price charged by a public utility to a customer for such 
 13.35  improvements.  
 13.36     (g) (h) "Large electric customer facility" means a customer 
 14.1   facility that imposes a peak electrical demand on an electric 
 14.2   utility's system of not less than 20,000 kilowatts, measured in 
 14.3   the same way as the utility that serves the customer facility 
 14.4   measures electrical demand for billing purposes, and for which 
 14.5   electric services are provided at retail on a single bill by a 
 14.6   utility operating in the state. 
 14.7      Sec. 2.  Minnesota Statutes 2000, section 216B.241, 
 14.8   subdivision 1a, is amended to read: 
 14.9      Subd. 1a.  [INVESTMENT, EXPENDITURE, AND CONTRIBUTION; 
 14.10  PUBLIC UTILITY.] (a) For purposes of this subdivision and 
 14.11  subdivision 2, "public utility" has the meaning given it in 
 14.12  section 216B.02, subdivision 4.  Each public utility shall spend 
 14.13  and invest for energy conservation improvements under this 
 14.14  subdivision and subdivision 2 the following amounts: 
 14.15     (1) for a utility that furnishes gas service, 0.5 percent 
 14.16  of its gross operating revenues from service provided in the 
 14.17  state; 
 14.18     (2) for a utility that furnishes electric service, 1.5 
 14.19  percent of its gross operating revenues from service provided in 
 14.20  the state; and 
 14.21     (3) for a utility that furnishes electric service and that 
 14.22  operates a nuclear-powered electric generating plant within the 
 14.23  state, two percent of its gross operating revenues from service 
 14.24  provided in the state. 
 14.25  For purposes of this paragraph (a), "gross operating revenues" 
 14.26  do not include revenues from large electric customer facilities 
 14.27  exempted by the commissioner of the department of public service 
 14.28  pursuant to under paragraph (b). 
 14.29     (b) The owner of a large electric customer facility may 
 14.30  petition the commissioner of the department of public 
 14.31  service commission to exempt both electric and gas utilities 
 14.32  serving the large energy customer facility from the investment 
 14.33  and expenditure requirements of paragraph (a) with respect to 
 14.34  retail revenues attributable to the facility.  At a minimum, the 
 14.35  petition must be supported by evidence relating to competitive 
 14.36  or economic pressures on the customer and a showing by the 
 15.1   customer of reasonable efforts to identify, evaluate, and 
 15.2   implement cost-effective conservation improvements at the 
 15.3   facility.  If a petition is filed on or before October 1 of any 
 15.4   year, the order of the commissioner commission to exempt 
 15.5   revenues attributable to the facility can be effective no 
 15.6   earlier than January 1 of the following year.  The commissioner 
 15.7   commission shall not grant an exemption if the commissioner 
 15.8   commission determines that granting the exemption is contrary to 
 15.9   the public interest.  The commissioner commission may, on 
 15.10  request of any person or on its own motion and after 
 15.11  investigation by the department, rescind any exemption granted 
 15.12  under this paragraph upon a determination that cost-effective 
 15.13  energy conservation improvements are available at the large 
 15.14  electric customer facility.  For the purposes of this paragraph, 
 15.15  "cost-effective" means that the projected total cost of the 
 15.16  energy conservation improvement at the large electric customer 
 15.17  facility is less than the projected present value of the energy 
 15.18  and demand savings resulting from the energy conservation 
 15.19  improvement.  For the purposes of investigations by the 
 15.20  commissioner department under this paragraph, the owner of any 
 15.21  large electric customer facility shall, upon request, provide 
 15.22  the commissioner department with updated information comparable 
 15.23  to that originally supplied in or with the owner's original 
 15.24  petition under this paragraph. 
 15.25     (c) The commissioner commission may require investments or 
 15.26  spending greater than the amounts required under this 
 15.27  subdivision for a public utility whose most recent advance 
 15.28  forecast required under section 216B.2422 or 216C.17 or 216E.08 
 15.29  projects a peak demand deficit of 100 megawatts or greater 
 15.30  within five years under mid-range forecast assumptions.  
 15.31     (d) A public utility or owner of a large electric customer 
 15.32  facility may appeal a decision of the commissioner under 
 15.33  paragraph (b) or (c) to the commission under subdivision 2.  In 
 15.34  reviewing a decision of the commissioner under paragraph (b) or 
 15.35  (c), the commission shall rescind the decision if it finds that 
 15.36  the required investments or spending will: 
 16.1      (1) not result in cost-effective energy conservation 
 16.2   improvements; or 
 16.3      (2) otherwise not be in the public interest. 
 16.4      (e) Each utility shall determine what portion of the amount 
 16.5   it sets aside for conservation improvement will be used for 
 16.6   conservation improvements under subdivision 2 and what portion 
 16.7   it will contribute to the energy and conservation account 
 16.8   established in subdivision 2a.  A public utility may propose to 
 16.9   the commissioner to designate that all or a portion of funds 
 16.10  contributed to the account established in subdivision 2a be used 
 16.11  for research and development projects.  Contributions must be 
 16.12  remitted to the commissioner of public service by February 1 of 
 16.13  each year.  Nothing in this subdivision prohibits a public 
 16.14  utility from spending or investing for energy conservation 
 16.15  improvement more than required in this subdivision. 
 16.16     Sec. 3.  Minnesota Statutes 2000, section 216B.241, 
 16.17  subdivision 1b, is amended to read: 
 16.18     Subd. 1b.  [CONSERVATION IMPROVEMENT BY COOPERATIVE 
 16.19  ASSOCIATION OR MUNICIPALITY.] (a) This subdivision applies to: 
 16.20     (1) a cooperative electric association that generates and 
 16.21  transmits electricity to associations that provide electricity 
 16.22  at retail including a cooperative electric association not 
 16.23  located in this state that serves associations or others in the 
 16.24  state provides retail electric service to its members; 
 16.25     (2) a municipality that provides electric service to retail 
 16.26  customers; and 
 16.27     (3) a municipality with gross operating revenues in excess 
 16.28  of $5,000,000 from sales of natural gas to retail customers.  
 16.29     (b) Each cooperative electric association and municipality 
 16.30  subject to this subdivision shall spend and invest for energy 
 16.31  conservation improvements under this subdivision the following 
 16.32  amounts: 
 16.33     (1) for a municipality, 0.5 percent of its gross operating 
 16.34  revenues from the sale of gas and one percent of its gross 
 16.35  operating revenues from the sale of electricity not purchased 
 16.36  from a public utility governed by subdivision 1a or a 
 17.1   cooperative electric association governed by this subdivision, 
 17.2   excluding gross operating revenues from electric and gas service 
 17.3   provided in the state to large electric customer facilities; and 
 17.4      (2) for a cooperative electric association, 1.5 percent of 
 17.5   its gross operating revenues from service provided in the state, 
 17.6   excluding gross operating revenues from service provided in the 
 17.7   state to large electric customer facilities indirectly through a 
 17.8   distribution cooperative electric association. 
 17.9      (c) Each municipality and cooperative electric association 
 17.10  subject to this subdivision shall identify and implement energy 
 17.11  conservation improvement spending and investments that are 
 17.12  appropriate for the municipality or association, except that a 
 17.13  municipality or association may not spend or invest for energy 
 17.14  conservation improvements that directly benefit a large electric 
 17.15  customer facility for which the commission has issued an 
 17.16  exemption under subdivision 1a, paragraph (b).  Each 
 17.17  municipality and cooperative electric association subject to 
 17.18  this subdivision may spend and invest annually up to 15 percent 
 17.19  of the total amount required to be spent and invested on energy 
 17.20  conservation improvements under this subdivision on research and 
 17.21  development projects that meet the definition of related to 
 17.22  energy conservation improvement in subdivision 1 
 17.23  and improvements that are funded directly by the municipality or 
 17.24  cooperative electric association.  Load management may be used 
 17.25  to meet the requirements of this subdivision if it reduces the 
 17.26  demand for or increases the efficiency of electric services.  A 
 17.27  generation and transmission cooperative electric association may 
 17.28  include as spending and investment required under this 
 17.29  subdivision conservation improvement spending and investment by 
 17.30  that provides energy services to cooperative electric 
 17.31  associations that provide electric service at retail to 
 17.32  consumers and that are served by the generation and transmission 
 17.33  association may invest in energy conservation improvements on 
 17.34  behalf of the associations it serves under an agreement between 
 17.35  the generation and transmission cooperative and each cooperative 
 17.36  electric association for funding the investments. 
 18.1      (d) By February 1 of each year, each municipality or 
 18.2   cooperative shall report to the commissioner department its 
 18.3   energy conservation improvement spending and investments with a 
 18.4   brief analysis of effectiveness in reducing consumption of 
 18.5   electricity or gas.  The report must specify the actual energy 
 18.6   savings or increased efficiency in the use of electricity within 
 18.7   the service territory of the municipality or association that is 
 18.8   the result of the spending and investments.  The commissioner 
 18.9   department shall review each report and make recommendations, 
 18.10  where appropriate, to the municipality or association to 
 18.11  increase the effectiveness of conservation improvement 
 18.12  activities.  The commissioner department shall also review each 
 18.13  report for whether a portion of the money spent on residential 
 18.14  conservation improvement programs is devoted to programs that 
 18.15  directly address the needs of renters and low-income persons 
 18.16  unless an insufficient number of appropriate programs are 
 18.17  available.  For the purposes of this subdivision and subdivision 
 18.18  2, "low-income" means an income of less than 185 percent of the 
 18.19  federal poverty level. 
 18.20     (e) As part of its spending for conservation improvement, a 
 18.21  municipality or association may contribute to the energy and 
 18.22  conservation account.  A municipality or association may propose 
 18.23  to the commissioner to designate that all or a portion of funds 
 18.24  contributed to the account be used for research and development 
 18.25  projects.  Any amount contributed must be remitted to the 
 18.26  commissioner of public service by February 1 of each year. 
 18.27     Sec. 4.  Minnesota Statutes 2000, section 216B.241, 
 18.28  subdivision 1c, is amended to read: 
 18.29     Subd. 1c.  [ENERGY-SAVING ENERGY-CONSERVATION GOALS.] The 
 18.30  commissioner shall establish energy-saving goals for energy 
 18.31  conservation improvement expenditures and shall evaluate an 
 18.32  energy conservation improvement program on how well it meets the 
 18.33  goals set.  (a) To the extent that an energy service provider 
 18.34  required to spend for or invest in energy conservation under 
 18.35  this section chooses to continue to directly spend for or invest 
 18.36  in conservation improvements until the final transition of 
 19.1   conservation funds to an energy efficiency utility under section 
 19.2   216B.2411, the service provider shall design and implement 
 19.3   energy conservation improvement programs that will and do result 
 19.4   in achieving the interim energy conservation goals developed 
 19.5   under the energy plan required in chapter 216E.  As part of that 
 19.6   plan, the department shall recommend and the commission shall 
 19.7   adopt energy savings goals for each energy service provider that 
 19.8   will apply during the transition to full funding of one or more 
 19.9   energy efficiency utilities.  The total of the individual goals 
 19.10  must equal the statewide goals established by the plan.  To 
 19.11  determine the prorated goals for each individual service 
 19.12  provider, the department and commission shall determine the 
 19.13  general potential for energy conservation within each service 
 19.14  territory based on: 
 19.15     (1) the percentage of the state's energy consumers within 
 19.16  the territory; 
 19.17     (2) the level of verifiable energy savings achieved over 
 19.18  the most recent five-year period within the territory; 
 19.19     (3) the relative mix of customer classes within the service 
 19.20  territory in light of the potential for energy savings from 
 19.21  each; 
 19.22     (4) the relative types, sizes, and ages of structures 
 19.23  within the service territory; and 
 19.24     (5) other factors relevant to energy conservation measures 
 19.25  already in place and the potential for future energy savings 
 19.26  within the service territory. 
 19.27     (b) Each energy service provider subject to this section 
 19.28  shall provide, in biennial conservation filings for public 
 19.29  utilities or in annual reports for municipal utilities and 
 19.30  cooperative electric associations, information sufficient for 
 19.31  making the determinations required under this section.  When 
 19.32  additional information is requested by the department or 
 19.33  commission, the service provider shall provide the information 
 19.34  in a timely manner not to exceed 15 working days. 
 19.35     Sec. 5.  Minnesota Statutes 2000, section 216B.241, 
 19.36  subdivision 2, is amended to read: 
 20.1      Subd. 2.  [PROGRAMS.] (a) The commissioner commission may 
 20.2   by rule require public utilities to make investments and 
 20.3   expenditures in energy conservation improvements, explicitly 
 20.4   setting forth the interest rates, prices, and terms under which 
 20.5   the improvements must be offered to the customers under 
 20.6   department rules in effect on December 31, 2000.  The required 
 20.7   programs must cover a two-year period, except for the transition 
 20.8   period under section 216B.2411, a public utility may opt to 
 20.9   propose to alter, add, or delete programs on an annual basis in 
 20.10  coordination with the energy efficiency utility and the 
 20.11  department.  The commissioner shall commission may require at 
 20.12  least one a public utility to establish a pilot program to use 
 20.13  energy conservation improvement funds to make investments in and 
 20.14  expenditures for energy from renewable resources such as solar, 
 20.15  wind, or biomass and shall give special consideration and 
 20.16  encouragement to programs that bring about significant net 
 20.17  savings through the use of energy-efficient lighting.  
 20.18  The commissioner department shall evaluate the program on the 
 20.19  basis of cost-effectiveness and the reliability of technologies 
 20.20  employed the actual energy conserved, the unit costs to conserve 
 20.21  the energy in relation to the unit costs to produce, transport, 
 20.22  and deliver energy from a new supply, including environmental 
 20.23  and socioeconomic costs, and shall make recommendations to the 
 20.24  commission for approval, modification, or rejection.  The rules 
 20.25  of the department must commission shall provide to the extent 
 20.26  practicable for a free choice, by consumers participating in the 
 20.27  program, of the device, method, material, or project 
 20.28  constituting the energy conservation improvement and for a free 
 20.29  choice of the seller, installer, or contractor of the energy 
 20.30  conservation improvement,; provided that, the device, method, 
 20.31  material, or project seller, installer, or contractor is duly 
 20.32  licensed, certified, approved, or qualified, including under the 
 20.33  residential conservation services program, where applicable.  
 20.34     (b) The commissioner commission may require a utility to 
 20.35  make an energy conservation improvement investment or 
 20.36  expenditure proposed by any person whenever the commissioner it 
 21.1   finds that the improvement will result in energy savings at a 
 21.2   total cost to the utility less than the cost to the utility to 
 21.3   produce or purchase an equivalent amount of new supply of 
 21.4   energy.  The commissioner shall nevertheless ensure that Every 
 21.5   public utility shall operate one or more conservation 
 21.6   improvement programs under periodic review by the department.  
 21.7   Load management may be used to meet the requirements for energy 
 21.8   conservation improvements under this section if it results in a 
 21.9   demonstrable reduction in consumption of energy until the end of 
 21.10  the transition period in section 216B.2411 unless the utility 
 21.11  opts to accelerate the transfer of funds to one or more energy 
 21.12  efficiency utilities, in which case the public utility is no 
 21.13  longer subject to this section once its entire allocated portion 
 21.14  of the total statewide conservation expenditure is transferred.  
 21.15  Each public utility subject to subdivision 1a may spend and 
 21.16  invest annually up to 15 percent of the total amount required to 
 21.17  be spent and invested on energy conservation improvements under 
 21.18  this section by the utility on research and development projects 
 21.19  that meet the definition of related to energy 
 21.20  conservation improvement in subdivision 1 and improvements that 
 21.21  are funded directly by the public utility.  A public utility may 
 21.22  not spend for or invest in energy conservation improvements that 
 21.23  directly benefit a large electric customer facility for which 
 21.24  the commissioner, prior to July 1, 2001, or the commission has 
 21.25  issued an exemption pursuant to subdivision 1a, paragraph (b).  
 21.26  The commissioner commission shall consider and may require a 
 21.27  utility to undertake a program suggested by the department, the 
 21.28  attorney general, or an outside source, including a political 
 21.29  subdivision or a nonprofit or community organization or any 
 21.30  other person. 
 21.31     (c) No utility may make an energy conservation improvement 
 21.32  under this section to a building envelope unless: 
 21.33     (1) it is the primary supplier of energy used for either 
 21.34  space heating or cooling in the building; 
 21.35     (2) the commissioner determines that special circumstances, 
 21.36  that would unduly restrict the availability of conservation 
 22.1   programs, warrant otherwise; or 
 22.2      (3) the utility has been awarded a contract under 
 22.3   subdivision 2a. 
 22.4      (d) The commissioner commission shall ensure that a portion 
 22.5   of the money spent on residential conservation improvement 
 22.6   programs is devoted to programs that directly address the needs 
 22.7   of renters and low-income persons unless an insufficient number 
 22.8   of appropriate programs are available. 
 22.9      (e) A utility, a political subdivision, or a nonprofit or 
 22.10  community organization that has suggested a program, the 
 22.11  attorney general acting on behalf of consumers and small 
 22.12  business interests, or a utility customer that has suggested a 
 22.13  program and is not represented by the attorney general under 
 22.14  section 8.33 may petition the commission to modify or revoke a 
 22.15  department decision under this section, and the commission may 
 22.16  do so if it determines that the program is not cost-effective, 
 22.17  does not adequately address the residential conservation 
 22.18  improvement needs of low-income persons, has a long-range 
 22.19  negative effect on one or more classes of customers, or is 
 22.20  otherwise not in the public interest.  The person petitioning 
 22.21  for commission review has the burden of proof.  The commission 
 22.22  shall reject a petition that, on its face, fails to make a 
 22.23  reasonable argument that a program is not in the public interest.
 22.24     Sec. 6.  Minnesota Statutes 2000, section 216B.241, 
 22.25  subdivision 2b, is amended to read: 
 22.26     Subd. 2b.  [RECOVERY OF EXPENSES.] The commission shall 
 22.27  allow a utility to recover expenses resulting from a 
 22.28  conservation improvement program required by the department and 
 22.29  contributions to the energy and conservation account, unless the 
 22.30  recovery would be inconsistent with a financial incentive 
 22.31  proposal approved by the commission.  In addition, a utility may 
 22.32  file annually, or the public utilities commission may require 
 22.33  the utility to file, and the commission may approve, rate 
 22.34  schedules containing provisions for the automatic adjustment of 
 22.35  charges for utility service in direct relation to changes in the 
 22.36  expenses of the utility for real and personal property taxes, 
 23.1   fees, and permits, the amounts of which the utility cannot 
 23.2   control.  A public utility is eligible to file for adjustment 
 23.3   for real and personal property taxes, fees, and permits under 
 23.4   this subdivision only if, in the year previous to the year in 
 23.5   which it files for adjustment, it has spent or invested at least 
 23.6   1.75 percent of its gross revenues from provision of electric 
 23.7   service, excluding gross operating revenues from electric 
 23.8   service provided in the state to large electric customer 
 23.9   facilities for which the commissioner of public service has 
 23.10  issued an exemption is in effect under subdivision 1a, paragraph 
 23.11  (b), and 0.6 percent of its gross revenues from provision of gas 
 23.12  service, excluding gross operating revenues from gas services 
 23.13  provided in the state to large electric customer facilities for 
 23.14  which the commissioner of public service has issued an exemption 
 23.15  is in effect under subdivision 1a, paragraph (b), for that year 
 23.16  for energy conservation improvements under this section. 
 23.17     Sec. 7.  [216B.2411] [ENERGY CONSERVATION FOR RELIABLE 
 23.18  ENERGY SUPPLY.] 
 23.19     Subdivision 1.  [ENERGY CONSERVATION PLAN AND PROGRAM.] The 
 23.20  commissioner of the department shall, as part of the energy plan 
 23.21  required under chapter 216E, determine the potential for energy 
 23.22  conservation improvements as defined in section 216B.241 and 
 23.23  establish goals for energy conservation.  The commissioner may 
 23.24  propose program strategies, screening and selection procedures, 
 23.25  budgets, and savings targets for the acquisition of energy 
 23.26  conservation resources as part of the plan. 
 23.27     Subd. 2.  [ENERGY CONSERVATION UTILITIES.] (a) The 
 23.28  commission shall certify one or more private entities to design 
 23.29  and implement energy conservation improvements in the state.  
 23.30  Certification may authorize operation statewide or may specify 
 23.31  geographic areas for operation and is for a period of no more 
 23.32  than five years, must contain terms and conditions consistent 
 23.33  with this chapter and chapters 216, 216A, 216C, and 216E as 
 23.34  recommended by the department and approved by the commission.  
 23.35  Certification renewal is subject to the same conditions as the 
 23.36  initial certification.  The commission may terminate a 
 24.1   certification for cause based on an evidentiary record and a 
 24.2   hearing and findings on the record.  The owners, directors, and 
 24.3   staff of an energy conservation utility must be independent of 
 24.4   any economic or structural affiliation with any entity that 
 24.5   provides electricity, natural gas, or petroleum products to 
 24.6   consumers in Minnesota.  An entity that applies for 
 24.7   certification, at a minimum, shall demonstrate knowledge about 
 24.8   and experience with effective energy conservation programs, 
 24.9   modern energy technologies, and marketing strategies. 
 24.10     (b) The commission shall prescribe by order the duties, 
 24.11  standards, and procedures related to the operations of energy 
 24.12  conservation utilities, as well as the procedures and criteria 
 24.13  for selecting and certifying the utilities.  The department, 
 24.14  under the commission's order, shall conduct a competitive 
 24.15  application process and shall recommend to the commission 
 24.16  selection and certification of one or more entities or the 
 24.17  rejection of all applicants and a new selection process. 
 24.18     (c) A certified energy conservation utility shall, in close 
 24.19  coordination with the department, design and implement energy 
 24.20  conservation programs.  All programs must be designed and 
 24.21  implemented to efficiently and effectively provide energy 
 24.22  conservation services to all energy consumers on a 
 24.23  nondiscriminatory and cost-effective basis. 
 24.24     (d) A conservation utility may provide energy conservation 
 24.25  services directly or under contracts with others and may solicit 
 24.26  and review bids to implement conservation programs or projects 
 24.27  from any entity, including private entities, local government 
 24.28  units, community organizations, public utilities, municipal 
 24.29  utilities, and cooperative electric associations, and may award 
 24.30  contracts to successful bidders.  The utility may seek and the 
 24.31  department may grant approval to negotiate contracts for 
 24.32  conservation services, without competitive bids, for innovative 
 24.33  services, for services provided by proven companies who provide 
 24.34  documentation of real energy savings resulting from their 
 24.35  proposed programs, or other services when competitive bidding 
 24.36  would serve little or no purpose.  Selection of energy 
 25.1   conservation contractors, by bid or negotiation, must be based 
 25.2   on the quality, reliability, cost effectiveness, replicability, 
 25.3   and sustainability of proposed conservation services.  To the 
 25.4   greatest extent possible, each energy conservation utility shall 
 25.5   coordinate its activities with all the other conservation 
 25.6   utilities and the department to ensure that the same level of 
 25.7   conservation services are to all similarly situated consumers 
 25.8   regardless of geographic location in the state and to ensure 
 25.9   that the activities of the conservation utilities and their 
 25.10  contractors are consistent with and are designed to meet the 
 25.11  goals of the state energy plan approved by the commission under 
 25.12  section 216E.06. 
 25.13     (e) An energy conservation utility shall report annually on 
 25.14  or before its certification anniversary to the commission and 
 25.15  the department.  The report must summarize the utility's 
 25.16  activities, energy savings resulting from those activities, its 
 25.17  business and operation plan for the next two-year period, and 
 25.18  expected energy savings over that time period.  The conservation 
 25.19  utility shall include in its report the results of an 
 25.20  independent audit performed by a certified public accountant and 
 25.21  shall make its books and records available for inspection by the 
 25.22  department and commission.  The commissioner or the commission 
 25.23  may order a conservation utility to include a specific program 
 25.24  or project in the utility's operation plan at any time and shall 
 25.25  ensure that all energy conservation utilities provide 
 25.26  conservation services needed in common by all consumers in the 
 25.27  state. 
 25.28     (f) The department shall assist energy conservation 
 25.29  utilities with the design of energy conservation programs and 
 25.30  projects and shall monitor and evaluate program and project 
 25.31  implementation and effectiveness and make recommendations to the 
 25.32  commission on certification, recertification, or decertification 
 25.33  of conservation utilities. 
 25.34     Subd. 3.  [TRANSITION TIME PERIOD AND FUNDING.] (a) An 
 25.35  energy conservation utility shall bill each public utility, 
 25.36  municipal utility, or cooperative electric association subject 
 26.1   to section 216B.241 for that utility's or association's share of 
 26.2   the programs and administrative costs of the energy conservation 
 26.3   utility.  The commission shall determine the maximum amount an 
 26.4   energy conservation utility may bill and each public utility's, 
 26.5   municipal utility's, or cooperative electric association's 
 26.6   prorated share of each energy conservation utility's costs based 
 26.7   on the relative gross operating revenues of each entity and the 
 26.8   geographic area in which the conservation utility is certified 
 26.9   to operate. 
 26.10     (b) The total amount all certified energy conservation 
 26.11  utilities may bill to public utilities, municipal utilities, and 
 26.12  cooperative electric associations that are subject to section 
 26.13  216B.241 may not exceed: 
 26.14     (1) $10,000,000 in fiscal year 2002; 
 26.15     (2) $20,000,000 in fiscal year 2003; 
 26.16     (3) $50,000,000 in fiscal year 2004; and 
 26.17     (4) an amount to be determined by the commission, but not 
 26.18  less than $75,000,000 in fiscal year 2005 and thereafter. 
 26.19     (c) Amounts billed are payable within 30 days of receipt, 
 26.20  may be used to meet energy conservation improvement obligations 
 26.21  under section 216B.241, and are recoverable as provided in 
 26.22  section 216B.241 when they are used to meet the obligations 
 26.23  under that section. 
 26.24     (d) An energy conservation utility, to the maximum extent 
 26.25  possible, shall use conservation dollars to benefit energy 
 26.26  consumers in the geographic area of the state from which the 
 26.27  dollars came. 
 26.28     Subd. 4.  [REQUIREMENTS; OPTIONS.] (a) An energy 
 26.29  conservation utility shall coordinate programs with the 
 26.30  weatherization assistance program, community-based energy 
 26.31  conservation programs, local government units, community 
 26.32  organizations, and the department to deliver conservation 
 26.33  services to households in the state whose income is less than 
 26.34  185 percent of the federal poverty level. 
 26.35     (b) A conservation utility may invest in research and 
 26.36  development projects and programs related to energy conservation 
 27.1   and development of modern energy technology that reduces the 
 27.2   need for new traditional energy resources but not more than 25 
 27.3   percent of a conservation utility's total budget may be used for 
 27.4   these purposes. 
 27.5      (c) When a public utility, municipal utility, or 
 27.6   cooperative electric association contracts with an energy 
 27.7   conservation utility, the dollar amount to execute the contract 
 27.8   may be credited against the obligation of the public utility, 
 27.9   municipal utility, or cooperative utility under subdivision 3 
 27.10  and section 216B.241 and need not be actually transferred 
 27.11  between the entities, unless the contract is not performed or is 
 27.12  not performed according to the specifications in the contract. 
 27.13     (d) A public utility, municipal utility, or cooperative 
 27.14  electric association subject to section 216B.241 may opt to 
 27.15  transfer more than its transitional share of conservation funds 
 27.16  under subdivision 3 in fiscal year 2002, 2003, or 2004.  If an 
 27.17  entity chooses this option, it must notify the commission by 
 27.18  September 1, 2001, for fiscal year 2002; by April 1, 2002, for 
 27.19  fiscal year 2003; or by April 1, 2003, for fiscal year 2004.  An 
 27.20  entity may opt to transfer all of its required conservation 
 27.21  improvement spending dollars required under section 216B.241 or 
 27.22  otherwise by the commission at any time prior to fiscal year 
 27.23  2005, and the only applicability of section 216B.241 is to 
 27.24  govern spending or investment of any amount utilities and 
 27.25  associations are required to spend under that section over the 
 27.26  amount required to be available for conservation utilities under 
 27.27  subdivision 3 and govern recovery by public utilities of amounts 
 27.28  spent for energy conservation through energy conservation 
 27.29  utilities. 
 27.30     Sec. 8.  [REPEALER.] 
 27.31     Minnesota Statutes 2000, section 216B.241, subdivision 2a, 
 27.32  is repealed. 
 27.33                             ARTICLE 3 
 27.34                     MODERN ENERGY TECHNOLOGIES 
 27.35     Section 1.  Minnesota Statutes 2000, section 116C.691, 
 27.36  subdivision 2, is amended to read: 
 28.1      Subd. 2.  [LARGE WIND ENERGY CONVERSION SYSTEM OR LWECS.] 
 28.2   "Large wind energy conversion system" or "LWECS" means any 
 28.3   combination of WECS wind energy conversion systems (WECS) with a 
 28.4   combined nameplate capacity of 5,000 kilowatts or more than 30 
 28.5   megawatts. 
 28.6      Sec. 2.  Minnesota Statutes 2000, section 116C.691, is 
 28.7   amended by adding a subdivision to read: 
 28.8      Subd. 2a.  [MEDIUM WIND ENERGY CONVERSION SYSTEMS OR 
 28.9   MWECS.] "Medium wind energy conversion system" or "MWECS" means 
 28.10  any combination of wind energy conversion systems (WECS) with a 
 28.11  nameplate capacity of five through 30 megawatts. 
 28.12     Sec. 3.  Minnesota Statutes 2000, section 116C.692, is 
 28.13  amended to read: 
 28.14     116C.692 [EXEMPTIONS.] 
 28.15     (a) The requirements of sections 116C.51 to 116C.69 do not 
 28.16  apply to the siting of LWECS, except for sections 116C.52; 
 28.17  116C.57, subdivision 4; 116C.59; 116C.62; 116C.63; 116C.645; 
 28.18  116C.65; 116C.68; and 116C.69, subdivision 3, which do apply. 
 28.19     (b) Siting of MWECS is subject to sections 216E.04 and 
 28.20  216E.12 and not to the requirements of sections 116C.51 to 
 28.21  116C.697. 
 28.22     (c) Any person may construct an SWECS without complying 
 28.23  with sections 116C.51 to 116C.69 and 116C.691 to 116C.697. 
 28.24     (c) (d) Nothing in sections 116C.691 to 116C.697 shall 
 28.25  preclude a local governmental unit from establishing 
 28.26  requirements for the siting and construction of SWECS. 
 28.27     Sec. 4.  Minnesota Statutes 2000, section 116C.779, is 
 28.28  amended to read: 
 28.29     116C.779 [FUNDING FOR RENEWABLE DEVELOPMENT.] 
 28.30     Subdivision 1.  [RENEWABLE DEVELOPMENT FUND ACCOUNT.] (a) 
 28.31  The public utility that operates the Prairie Island nuclear 
 28.32  generating plant must transfer to a an interest-bearing 
 28.33  renewable development account $500,000 each year for each dry 
 28.34  cask containing spent fuel that is located at the independent 
 28.35  spent fuel storage installation at Prairie Island after January 
 28.36  1, 1999.  Earnings, such as interest, dividends, and any other 
 29.1   earnings from fund assets, must be credited to the account.  The 
 29.2   fund transfer must be made if waste is stored in a cask for any 
 29.3   part of a year.  Funds in the account may be expended only for 
 29.4   development of renewable energy sources.  Preference must be 
 29.5   given to development of renewable energy source projects located 
 29.6   within the state. 
 29.7      (b) Subd. 2.  [COMMISSION APPROVAL FOR EXPENDITURES.] 
 29.8   Expenditures from the account may only be made after approval by 
 29.9   order of the public utilities commission upon a petition by the 
 29.10  public utility. 
 29.11     Sec. 5.  Minnesota Statutes 2000, section 216B.164, 
 29.12  subdivision 3, is amended to read: 
 29.13     Subd. 3.  [PURCHASES; SMALL FACILITIES.] (a) For a 
 29.14  qualifying facility having two megawatts or less than 
 29.15  40-kilowatt nameplate capacity, the customer shall must be 
 29.16  billed for the net energy supplied by the utility according to 
 29.17  the applicable rate schedule for sales to that class of customer.
 29.18     (b) In the case of net input into the utility system by a 
 29.19  qualifying facility having less than 40-kilowatt nameplate 
 29.20  capacity, compensation to the customer shall must be at a per 
 29.21  kilowatt hour rate determined under paragraph (b) or (c) of this 
 29.22  subdivision.  
 29.23     (b) In setting rates, the commission shall consider the 
 29.24  fixed distribution costs to the utility not otherwise accounted 
 29.25  for in the basic monthly charge and shall ensure that the costs 
 29.26  charged to the qualifying facility are not discriminatory in 
 29.27  relation to the costs charged to other customers of the utility. 
 29.28  The commission shall set the rates for net input into the 
 29.29  utility system based on avoided costs as defined in the Code of 
 29.30  Federal Regulations, title 18, section 292.101(b)(6), the 
 29.31  factors listed in Code of Federal Regulations, title 18, section 
 29.32  292.304, and all other relevant factors.  
 29.33     (c) Notwithstanding any provision in this chapter to the 
 29.34  contrary, a qualifying facility having less than 40-kilowatt 
 29.35  capacity may elect that the compensation for net input by the 
 29.36  qualifying facility into the utility system shall be at the 
 30.1   average retail utility energy rate.  "Average retail utility 
 30.2   energy rate" is defined as the average of the retail energy 
 30.3   rates, exclusive of special rates based on income, age, or 
 30.4   energy conservation, according to the applicable rate schedule 
 30.5   of the utility for sales to that class of customer. 
 30.6      (c) Notwithstanding subdivision 4, for a qualifying 
 30.7   facility of 40-kilowatt capacity through two megawatts of 
 30.8   nameplate capacity, the compensation for net input by the 
 30.9   qualifying facility into the utility system is the market price 
 30.10  for energy at the time the facility began putting energy into 
 30.11  the utility system and must be adjusted to the present market 
 30.12  price at least once every three years.  For the purposes of this 
 30.13  paragraph, "market price" means the average price paid by all 
 30.14  utilities in Minnesota for energy from facilities that utilize 
 30.15  the same energy source as the qualifying facility.  
 30.16     (d) If the qualifying facility is interconnected with a 
 30.17  nongenerating utility which that has a sole source contract with 
 30.18  a municipal power agency or a generation and transmission 
 30.19  utility, the nongenerating utility may elect to treat its 
 30.20  purchase of any net input under this subdivision as being made 
 30.21  on behalf of its supplier and shall must be reimbursed by its 
 30.22  supplier for any additional costs incurred in making the 
 30.23  purchase.  Qualifying facilities having less than 40-kilowatt 
 30.24  capacity may, at the customer's option, elect to be governed by 
 30.25  the provisions of subdivision 4.  
 30.26     Sec. 6.  Minnesota Statutes 2000, section 216B.164, 
 30.27  subdivision 6, is amended to read: 
 30.28     Subd. 6.  [RULES AND UNIFORM CONTRACT.] (a) The commission 
 30.29  shall promulgate rules to implement the provisions of this 
 30.30  section.  The commission shall also establish a uniform 
 30.31  statewide form of contract for use between utilities and a 
 30.32  qualifying facility having a capacity of two megawatts or less 
 30.33  than 40-kilowatt capacity.  
 30.34     (b) The commission shall require the qualifying facility to 
 30.35  provide the utility with reasonable access to the premises and 
 30.36  equipment of the qualifying facility if the particular 
 31.1   configuration of the qualifying facility precludes disconnection 
 31.2   or testing of the qualifying facility from the utility side of 
 31.3   the interconnection with the utility remaining responsible for 
 31.4   its personnel.  
 31.5      (c) The uniform statewide form of contract shall must be 
 31.6   applied to all new and existing interconnections established 
 31.7   between a utility and a qualifying facility having less than 
 31.8   40-kilowatt capacity, except that existing contracts may remain 
 31.9   in force until written notice of election that the uniform 
 31.10  statewide contract form applies is given by either party to the 
 31.11  other, with the notice being of the shortest time period 
 31.12  permitted under the existing contract for termination of the 
 31.13  existing contract by either party, but not less than ten nor 
 31.14  longer than 30 days.  
 31.15     Sec. 7.  [216B.68] [DEFINITIONS.] 
 31.16     Subdivision 1.  [SCOPE.] The words and terms used in 
 31.17  sections 216B.68 to 216B.75 have the meanings given them in this 
 31.18  section. 
 31.19     Subd. 2.  [APPLICATION FOR INTERCONNECTION AND PARALLEL 
 31.20  OPERATION.] "Application for interconnection and parallel 
 31.21  operation with the utility system or application" means a 
 31.22  standard form of application developed by the commissioner and 
 31.23  approved by the commission. 
 31.24     Subd. 3.  [COMPANY.] "Company" means an electric utility 
 31.25  operating a distribution system. 
 31.26     Subd. 4.  [ELECTRIC UTILITY.] "Electric utility" means all 
 31.27  electric utilities that own and operate equipment in the state 
 31.28  for furnishing electric service at retail. 
 31.29     Subd. 5.  [CUSTOMER.] "Customer" means any individual 
 31.30  person or entity interconnected to the company's utility system 
 31.31  for the purpose of receiving or exporting electric power from or 
 31.32  to the company's utility system. 
 31.33     Subd. 6.  [DISTRIBUTED GENERATION OR ON-SITE DISTRIBUTED 
 31.34  GENERATION.] "Distributed generation" or "on-site distributed 
 31.35  generation" means an electrical generating facility located at a 
 31.36  customer's point of delivery or point of common coupling of ten 
 32.1   megawatts or less and connected at a voltage less than or equal 
 32.2   to 60 kilovolts that may be connected in parallel operation to 
 32.3   the utility system. 
 32.4      Subd. 7.  [FACILITY.] "Facility" means an electrical 
 32.5   generating installation consisting of one or more on-site 
 32.6   distributed generation units.  The total capacity of a 
 32.7   facility's individual on-site distributed generation units may 
 32.8   exceed ten megawatts; however, no more than ten megawatts of a 
 32.9   facility's capacity will be interconnected at any point in time 
 32.10  at the point of common coupling under this section. 
 32.11     Subd. 8.  [INTERCONNECTION.] "Interconnection" means the 
 32.12  physical connection of distributed generation to the utility 
 32.13  system in accordance with the requirements of this section so 
 32.14  that parallel operation can occur. 
 32.15     Subd. 9.  [INTERCONNECTION AGREEMENT.] "Interconnection 
 32.16  agreement" means the standard form of agreement, developed and 
 32.17  approved by the commission.  The interconnection agreement sets 
 32.18  forth the contractual conditions under which a company and a 
 32.19  customer agree that one or more facilities may be interconnected 
 32.20  with the company's utility system. 
 32.21     Subd. 10.  [INVERTER-BASED PROTECTIVE 
 32.22  FUNCTION.] "Inverter-based protective function" means a function 
 32.23  of an inverter system, carried out using hardware and software, 
 32.24  that is designed to prevent unsafe operating conditions from 
 32.25  occurring before, during, and after the interconnection of an 
 32.26  inverter-based static power converter unit with a utility 
 32.27  system.  For purposes of this definition, unsafe operating 
 32.28  conditions are conditions that, if left uncorrected, would 
 32.29  result in harm to personnel, damage to equipment, unacceptable 
 32.30  system instability, or operation outside legally established 
 32.31  parameters affecting the quality of service to other customers 
 32.32  connected to the utility system. 
 32.33     Subd. 11.  [NETWORK SERVICE.] "Network service" means two 
 32.34  or more utility primary distribution feeder sources electrically 
 32.35  tied together on the secondary side, which is the low-voltage 
 32.36  side, to form one power source for one or more customers.  The 
 33.1   service is designed to maintain service to the customers even 
 33.2   after the loss of one of these primary distribution feeder 
 33.3   sources. 
 33.4      Subd. 12.  [PARALLEL OPERATION.] "Parallel operation" means 
 33.5   the operation of on-site distributed generation by a customer 
 33.6   while the customer is connected to the company's utility system. 
 33.7      Subd. 13.  [POINT OF COMMON COUPLING.] "Point of common 
 33.8   coupling" means the point where the electrical conductors of the 
 33.9   company utility system are connected to the customer's 
 33.10  conductors and where any transfer of electric power between the 
 33.11  customer and the utility system takes place, such as switchgear 
 33.12  near the meter. 
 33.13     Subd. 14.  [PRECERTIFIED EQUIPMENT.] "Precertified 
 33.14  equipment" means a specific generating and protective equipment 
 33.15  system or systems that have been certified as meeting the 
 33.16  applicable parts of this section relating to safety and 
 33.17  reliability by an entity approved by the commission. 
 33.18     Subd. 15.  [PRE-INTERCONNECTION STUDY.] 
 33.19  "Pre-interconnection study" means a study or studies that may be 
 33.20  undertaken by a company in response to its receipt of a 
 33.21  completed application for interconnection and parallel operation 
 33.22  with the utility system.  Pre-interconnection studies may 
 33.23  include, but are not limited to, service studies, coordination 
 33.24  studies, and utility system impact studies. 
 33.25     Subd. 16.  [STABILIZED.] "Stabilized" means that, following 
 33.26  a disturbance, a company utility system has returned to the 
 33.27  normal range of voltage and frequency for a duration of two 
 33.28  minutes or a shorter time as mutually agreed to by the company 
 33.29  and customer. 
 33.30     Subd. 17.  [TARIFF OR TARIFF FOR INTERCONNECTION AND 
 33.31  PARALLEL OPERATION OF DISTRIBUTED GENERATION.] "Tariff" or 
 33.32  "Tariff for interconnection and parallel operation of 
 33.33  distributed generation" means the commission-developed and 
 33.34  commission-approved tariff for interconnection and parallel 
 33.35  operation of distributed generation, including the application 
 33.36  for interconnection and parallel operation of distributed 
 34.1   generation and pre-interconnection study fee schedule. 
 34.2      Subd. 18.  [UNIT.] "Unit" means a power generator. 
 34.3      Subd. 19.  [UTILITY SYSTEM.] "Utility system" means a 
 34.4   company's distribution system below 60 kilovolts to which the 
 34.5   generation equipment is interconnected. 
 34.6      Sec. 8.  [216B.69] [INTERCONNECTION OF ON-SITE DISTRIBUTED 
 34.7   GENERATION.] 
 34.8      Subdivision 1.  [PURPOSE.] The purpose of sections 216B.68 
 34.9   to 216B.75 is to state the terms and conditions that govern the 
 34.10  interconnection and parallel operation of on-site distributed 
 34.11  generation to provide cost savings and reliability benefits to 
 34.12  customers, to establish technical requirements that will promote 
 34.13  the safe and reliable parallel operation of on-site distributed 
 34.14  generation resources, to enhance both the reliability of 
 34.15  electric service and economic efficiency in the production and 
 34.16  consumption of electricity, and to promote the use of 
 34.17  distributed resources in order to provide electric system 
 34.18  benefits during periods of capacity constraints. 
 34.19     Subd. 2.  [OBLIGATION TO SERVE; TARIFF AND OTHER 
 34.20  FILINGS.] (a) No later than 270 days after the effective date of 
 34.21  this section, each electric utility shall file tariffs for 
 34.22  interconnection and parallel operation of distributed generation 
 34.23  in conformance with sections 216B.68 to 216B.75.  The electric 
 34.24  utility may file a new tariff or a modification of an existing 
 34.25  tariff.  These tariffs must ensure that backup power, 
 34.26  supplemental power, and maintenance power are available to all 
 34.27  customers and customer classes that desire this service.  Any 
 34.28  modifications of existing tariffs or offerings of new tariffs 
 34.29  relating to this section must be consistent with the 
 34.30  commission-approved form.  
 34.31     (b) Concurrent with the tariff filing in this section, each 
 34.32  utility shall submit: 
 34.33     (1) a schedule detailing the charges of interconnection 
 34.34  studies and all supporting cost data for the charges; 
 34.35     (2) a standard application for interconnection and parallel 
 34.36  operation of distributed generation; and 
 35.1      (3) the interconnection agreement approved by the 
 35.2   commission. 
 35.3      Sec. 9.  [216B.70] [DISCONNECTION AND RECONNECTION.] 
 35.4      Subdivision 1.  [WHEN DISCONNECTION ALLOWED.] A utility may 
 35.5   disconnect a distributed generation unit from the utility system 
 35.6   if: 
 35.7      (1) the interconnection agreement with a customer expires 
 35.8   or terminates, in accordance with the terms of the agreement; 
 35.9      (2) the facility is not in compliance with the technical 
 35.10  requirements specified by the commissioner; 
 35.11     (3) continued interconnection will endanger persons or 
 35.12  property; or 
 35.13     (4) written notice is provided at least seven business days 
 35.14  prior to a service interruption for routine maintenance, 
 35.15  repairs, and utility system modifications. 
 35.16     Subd. 2.  [INCREMENTAL DEMAND CHARGES.] During the term of 
 35.17  an interconnection agreement, a utility may require that a 
 35.18  customer disconnect its distributed generation unit or take it 
 35.19  off-line as a result of utility system conditions.  The company 
 35.20  may not assess the customer incremental demand charges arising 
 35.21  from disconnecting the distributed generator as directed by the 
 35.22  company during these periods. 
 35.23     Sec. 10.  [216B.71] [PRE-INTERCONNECTION STUDIES FOR 
 35.24  NONNETWORK INTERCONNECTION OF DISTRIBUTED GENERATION.] 
 35.25     Subdivision 1.  [STUDIES.] A utility may conduct a service 
 35.26  study, coordination study, or utility system impact study prior 
 35.27  to interconnection of a distributed generation facility.  When a 
 35.28  study is deemed necessary, the scope of the study must be based 
 35.29  on the characteristics of the particular distributed generation 
 35.30  facility to be interconnected and the utility's system at the 
 35.31  specific proposed location.  By agreement between the utility 
 35.32  and its customer, a study related to interconnection of 
 35.33  distributed generation on the customer's premises may be 
 35.34  conducted by a qualified third party. 
 35.35     Subd. 2.  [CUSTOMER FEE.] (a) A utility may not charge a 
 35.36  customer a fee to conduct a pre-interconnection study for 
 36.1   precertified distributed generation units up to 500 kilowatts 
 36.2   that export not more than 15 percent of the total load on a 
 36.3   single radial feeder and contribute not more than 25 percent of 
 36.4   the maximum potential short circuit current on a single radial 
 36.5   feeder. 
 36.6      (b) Prior to the interconnection of a distributed 
 36.7   generation facility not described in paragraph (a), a utility 
 36.8   may charge a customer a fee to offset its costs incurred in the 
 36.9   conduct of a pre-interconnection study.  
 36.10     Subd. 3.  [WHEN UTILITY CONDUCTS STUDY.] When a utility 
 36.11  conducts an interconnection study, paragraphs (a) to (d) apply: 
 36.12     (a) The conduct of the pre-interconnection study may not 
 36.13  take more than four weeks. 
 36.14     (b) A utility shall prepare written reports of the study 
 36.15  findings and make them available to the customer. 
 36.16     (c) The study must consider both the costs incurred and the 
 36.17  benefits realized as a result of the interconnection of 
 36.18  distributed generation to the company's utility system. 
 36.19     (d) The utility shall provide the customer with an estimate 
 36.20  of the study cost before the utility initiates the study. 
 36.21     Sec. 11.  [216B.72] [PRE-INTERCONNECTION STUDIES FOR 
 36.22  NETWORK INTERCONNECTION OF DISTRIBUTED GENERATION.] 
 36.23     Subdivision 1.  [NOTICE AND FEES.] (a) Prior to charging a 
 36.24  pre-interconnection study fee for a network interconnection of 
 36.25  distributed generation, a utility shall first advise the 
 36.26  customer of the potential problems associated with 
 36.27  interconnection of distributed generation with its network 
 36.28  system.  
 36.29     (b) For potential interconnections to network systems, a 
 36.30  pre-interconnection study fee may not be assessed for a facility 
 36.31  with inverter systems under 20 kilowatts.  For all other 
 36.32  facilities, the utility may charge the customer a fee to offset 
 36.33  its costs incurred in the conduct of the pre-interconnection 
 36.34  study.  
 36.35     Subd. 2.  [REQUIREMENTS WHEN UTILITY CONDUCTS STUDY.] When 
 36.36  a utility conducts an interconnection study, paragraphs (a) to 
 37.1   (d) apply: 
 37.2      (a) The conduct of a pre-interconnection study may not take 
 37.3   more than four weeks. 
 37.4      (b) A utility shall prepare written reports of the study 
 37.5   findings and make them available to the customer. 
 37.6      (c) The study must consider both the costs incurred and the 
 37.7   benefits realized as a result of the interconnection of 
 37.8   distributed generation to the utility's system. 
 37.9      (d) The utility shall provide the customer with an estimate 
 37.10  of the study cost before the utility initiates the study. 
 37.11     Sec. 12.  [216B.73] [EQUIPMENT PRECERTIFICATION.] (a) The 
 37.12  commission may approve one or more entities that shall 
 37.13  precertify equipment as described under this section. 
 37.14     (b) Testing organizations or facilities capable of 
 37.15  analyzing the function, control, and protective systems of 
 37.16  distributed generation units may request to be certified as 
 37.17  testing organizations. 
 37.18     (c) Distributed generation units that are certified to be 
 37.19  in compliance by an approved testing facility or organization 
 37.20  must be installed on a company utility system in accordance with 
 37.21  an approved interconnection control and protection scheme 
 37.22  without further review of their design by the utility. 
 37.23     Sec. 13.  [216B.74] [TIME FOR PROCESSING APPLICATIONS FOR 
 37.24  INTERCONNECTION.] 
 37.25     (a) The interconnection of distributed generation to the 
 37.26  utility system must take place within the schedules described in 
 37.27  paragraphs (b) to (f): 
 37.28     (b) For a facility with precertified equipment, 
 37.29  interconnection must take place within four weeks of the 
 37.30  utility's receipt of a completed interconnection application. 
 37.31     (c) For facilities without precertified equipment, 
 37.32  connection must take place within six weeks of the utility's 
 37.33  receipt of a completed application. 
 37.34     (d) If interconnection of a particular facility will 
 37.35  require substantial capital upgrades to the utility system, the 
 37.36  company shall provide the customer an estimate of the schedule 
 38.1   and the customer's cost for the upgrade.  If the customer 
 38.2   desires to proceed with the upgrade, the customer and the 
 38.3   company shall enter into a contract for the completion of the 
 38.4   upgrade.  The interconnection must take place no later than two 
 38.5   weeks following the completion of the upgrade.  The utility 
 38.6   shall employ best reasonable efforts to complete the system 
 38.7   upgrade in the shortest time reasonably practical. 
 38.8      (e) A utility shall use best reasonable efforts to 
 38.9   interconnect facilities within the time frames described in this 
 38.10  section.  If in a particular instance, a utility determines that 
 38.11  it cannot interconnect a facility within the time frames stated 
 38.12  in this section, it must notify the applicant in writing of that 
 38.13  fact.  The notification must identify any reasons 
 38.14  interconnection could not be performed in accordance with the 
 38.15  schedule and provide an estimated date for interconnection. 
 38.16     (f) Applications for interconnection and parallel operation 
 38.17  of distributed generation must be processed by the utility in a 
 38.18  nondiscriminatory manner and in the order that they are 
 38.19  received.  It is recognized that certain applications may 
 38.20  require minor modifications while they are being reviewed by the 
 38.21  utility.  These minor modifications to a pending application do 
 38.22  not require that it be considered incomplete and treated as a 
 38.23  new or separate application. 
 38.24     Sec. 14.  [216B.75] [REPORTING REQUIREMENTS.] 
 38.25     (a) Each electric utility shall maintain records concerning 
 38.26  applications received for interconnection and parallel operation 
 38.27  of distributed generation.  The records must include the date 
 38.28  each application is received, documents generated in the course 
 38.29  of processing each application, correspondence regarding each 
 38.30  application, and the final disposition of each application.  
 38.31     (b) By March 30 of each year, every electric utility shall 
 38.32  file with the commission a distributed generation 
 38.33  interconnection report for the preceding calendar year that 
 38.34  identifies each distributed generation facility interconnected 
 38.35  with the utility's distribution system.  The report must list 
 38.36  the new distributed generation facilities interconnected with 
 39.1   the system since the previous year's report, any distributed 
 39.2   generation facilities no longer interconnected with the 
 39.3   utility's system since the previous report, the capacity of each 
 39.4   facility, and the feeder or other point on the company's utility 
 39.5   system where the facility is connected.  The annual report must 
 39.6   also identify all applications for interconnection received 
 39.7   during the previous one-year period, and the disposition of the 
 39.8   applications. 
 39.9      Sec. 15.  Minnesota Statutes 2000, section 216C.41, 
 39.10  subdivision 1, is amended to read: 
 39.11     Subdivision 1.  [DEFINITIONS.] (a) The definitions in this 
 39.12  subdivision apply to this section. 
 39.13     (b) "Qualified hydroelectric facility" means a 
 39.14  hydroelectric generating facility in this state that: 
 39.15     (1) is located at the site of a dam, if the dam was in 
 39.16  existence as of March 31, 1994; and 
 39.17     (2) either begins generating electricity after July 1, 
 39.18  1994, or resumes generating electricity after substantial 
 39.19  refurbishing of the facility that begins after July 1, 2001. 
 39.20     (c) "Qualified wind energy conversion facility" means a 
 39.21  wind energy conversion system that: 
 39.22     (1) produces two megawatts or less of electricity as 
 39.23  measured by nameplate rating and begins generating electricity 
 39.24  after June 30, 1997, and before July 1, 1999; 
 39.25     (2) begins generating electricity after June 30, 1999, 
 39.26  produces two megawatts or less of electricity as measured by 
 39.27  nameplate rating, and is: 
 39.28     (i) located within one county and owned by a natural person 
 39.29  who owns the land where the facility is sited; 
 39.30     (ii) owned by a Minnesota small business as defined in 
 39.31  section 645.445; 
 39.32     (iii) owned by a nonprofit organization; or 
 39.33     (iv) owned by a tribal council if the facility is located 
 39.34  within the boundaries of the reservation; or 
 39.35     (v) owned by a municipal utility or a cooperative electric 
 39.36  association; 
 40.1      (3) begins generating electricity after June 30, 1999, 
 40.2   produces seven megawatts or less of electricity as measured by 
 40.3   nameplate rating, and: 
 40.4      (i) is owned by a cooperative organized under chapter 308A; 
 40.5   and 
 40.6      (ii) all shares and membership in the cooperative are held 
 40.7   by natural persons or estates, at least 51 percent of whom 
 40.8   reside in a county or contiguous to a county where the wind 
 40.9   energy production facilities of the cooperative are located.; or 
 40.10     (4) begins generating electricity after June 30, 2001, 
 40.11  produces 20 megawatts or less of electricity as measured by 
 40.12  nameplate rating, is not, in whole or in part, used to meet the 
 40.13  wind power mandate in section 216B.2423, and is not located in 
 40.14  the counties of Lincoln, Lyon, Murray, Nobles, Pipestone, or 
 40.15  Rock. 
 40.16     (d) "Qualified solar energy conversion facility" means a 
 40.17  solar energy conversion system that is located in this state, 
 40.18  that is not owned by a public utility or a subsidiary or 
 40.19  affiliate of a public utility, and that produces ten or less 
 40.20  kilowatts of electricity as measured by nameplate rating.  
 40.21     Sec. 16.  Minnesota Statutes 2000, section 216C.41, 
 40.22  subdivision 3, is amended to read: 
 40.23     Subd. 3.  [ELIGIBILITY WINDOW.] Payments may be made under 
 40.24  this section only for electricity generated: 
 40.25     (1) from a qualified hydroelectric facility that is 
 40.26  operational and generating electricity before December 31, 
 40.27  2001 2005; or 
 40.28     (2) from a qualified wind energy conversion facility that 
 40.29  is operational and generating electricity before January 1, 2005 
 40.30  2007; or 
 40.31     (3) from a qualified solar energy conversion facility that 
 40.32  is operational and generating electricity before January 1, 2010.
 40.33     Sec. 17.  Minnesota Statutes 2000, section 216C.41, 
 40.34  subdivision 4, is amended to read: 
 40.35     Subd. 4.  [PAYMENT PERIOD.] (a) A facility may receive 
 40.36  payments under this section for a ten-year period.  No payment 
 41.1   under this section may be made for electricity generated: 
 41.2      (1) by a qualified hydroelectric facility after December 
 41.3   31, 2010; or 2015; 
 41.4      (2) by a qualified wind energy conversion facility after 
 41.5   December 31, 2015 2017; or 
 41.6      (3) by a qualified solar energy conversion facility after 
 41.7   December 31, 2020.  
 41.8      (b) The payment period begins and runs consecutively from 
 41.9   the first year in which electricity generated from the facility 
 41.10  is eligible for incentive payment. 
 41.11     Sec. 18.  Minnesota Statutes 2000, section 216C.41, 
 41.12  subdivision 5, is amended to read: 
 41.13     Subd. 5.  [AMOUNT OF PAYMENT.] (a) An incentive payment is 
 41.14  based on the number of kilowatt hours of electricity generated. 
 41.15  The amount of the payment is: 
 41.16     (1) 1.5 cents per kilowatt hour. of electricity generated 
 41.17  by a qualified hydroelectric facility or a qualified wind 
 41.18  conversion energy facility as defined in subdivision 1, 
 41.19  paragraph (c), clause (1), (2), or (3); 
 41.20     (2) one cent per kilowatt hour of electricity generated by 
 41.21  a qualified wind energy conversion facility as defined in 
 41.22  subdivision 1, paragraph (c), clause (4); and 
 41.23     (3) ten cents per kilowatt hour of electricity generated by 
 41.24  a qualified solar energy conversion facility. 
 41.25     (b) For electricity generated by qualified wind energy 
 41.26  conversion facilities, the incentive payment under this section 
 41.27  is limited to no more than 100 300 megawatts of nameplate 
 41.28  capacity.  During any period in which qualifying claims for 
 41.29  incentive payments exceed 100 300 megawatts of nameplate 
 41.30  capacity, the payments must be made to producers in the order in 
 41.31  which the production capacity was brought into production.  
 41.32     (c) Beginning January 1, 2002, a qualified wind energy 
 41.33  conversion facility defined under subdivision 1, paragraph (c), 
 41.34  clause (1), (2), or (3), may not be located within five miles of 
 41.35  another qualified wind energy conversion facility constructed 
 41.36  within the same calendar year and owned by the same person.  For 
 42.1   the purposes of this paragraph, the department shall determine 
 42.2   that the same person owns two qualified wind energy conversion 
 42.3   facilities when the underlying ownership structure contains 
 42.4   similar persons or entities, other than a person or entity that 
 42.5   provides equity financing, even if the ownership shares differ 
 42.6   between the facilities. 
 42.7      (d) Not more than 150 megawatts of nameplate capacity may 
 42.8   receive incentive payments for qualified facilities as defined 
 42.9   in subdivision 1, paragraph (c), clause (4).  Nothing in this 
 42.10  section reserves any number of megawatts for facilities that 
 42.11  qualify under subdivision 1, paragraph (c), clause (4). 
 42.12     (e) Notwithstanding subdivision 2, for a qualified wind 
 42.13  energy conversion facility with a nameplate rating of 100 
 42.14  kilowatts or less in operation on July 1, 2001, or thereafter, 
 42.15  and for a qualified solar energy conversion facility that is in 
 42.16  operation on July 1, 2001, or thereafter, regardless of 
 42.17  installation date, the incentive payment is based on the total 
 42.18  amount of electricity generated by the facility, whether it is 
 42.19  used on-site or otherwise or sold to another entity.  For 
 42.20  qualified solar energy conversion facilities, the incentive 
 42.21  payment under this section is limited to 25 megawatts of 
 42.22  nameplate capacity. 
 42.23     (f) Notwithstanding subdivision 2, incentive payments may 
 42.24  be made only to the facility owner unless the owner, in writing, 
 42.25  directs that payment be made to another person or entity. 
 42.26     Sec. 19.  Minnesota Statutes 2000, section 216C.41, is 
 42.27  amended by adding a subdivision to read: 
 42.28     Subd. 6.  [OWNERSHIP; FINANCING; CURE.] (a) For the 
 42.29  purposes of subdivision 1, paragraph (c), clause (2), a wind 
 42.30  energy conversion facility qualifies if it is owned at least 51 
 42.31  percent by one or more of any combination of the entities listed 
 42.32  in that clause. 
 42.33     (b) A subsequent owner of a qualified facility may continue 
 42.34  to receive the incentive payment for the duration of the 
 42.35  original payment period if the subsequent owner qualifies for 
 42.36  the incentive under subdivision 1. 
 43.1      (c) Nothing in this section may be construed to deny 
 43.2   incentive payment to an otherwise qualified facility that has 
 43.3   obtained debt or equity financing for construction or operation 
 43.4   as long as the ownership requirements of subdivision 1 and this 
 43.5   subdivision are met.  If, during the incentive payment period 
 43.6   for a qualified facility, the owner of the facility is in 
 43.7   default of a lending agreement and the lender takes possession 
 43.8   of and operates the facility and makes reasonable efforts to 
 43.9   transfer ownership of the facility to an entity other than the 
 43.10  lender, the lender may continue to receive the incentive payment 
 43.11  for electricity generated and sold by the facility for a period 
 43.12  not to exceed 18 months.  A lender who takes possession of a 
 43.13  facility shall notify the commissioner immediately on taking 
 43.14  possession and, at least quarterly, document efforts to transfer 
 43.15  ownership of the facility. 
 43.16     (d) If, during the incentive payment period, a qualified 
 43.17  facility loses the right to receive the incentive because of 
 43.18  changes in ownership, the facility may regain the right to 
 43.19  receive the incentive upon cure of the ownership structure that 
 43.20  resulted in the loss of eligibility and may reapply for the 
 43.21  incentive, but in no case may the payment period be extended 
 43.22  beyond the original ten-year limit. 
 43.23     (e) A subsequent or requalifying owner under paragraph (b) 
 43.24  or (d) retains the facility's original priority order for 
 43.25  incentive payments as long as the ownership structure 
 43.26  requalifies within two years from the date the facility became 
 43.27  unqualified or two years from the date a lender takes possession 
 43.28  of the facility.  
 43.29                             ARTICLE 4
 43.30                      MISCELLANEOUS PROVISIONS 
 43.31     Section 1.  Minnesota Statutes 2000, section 216A.07, is 
 43.32  amended by adding a subdivision to read: 
 43.33     Subd. 7.  [GIFTS.] Notwithstanding section 7.09, the 
 43.34  commissioner may receive and accept, on behalf of the department 
 43.35  of commerce, any gift, bequest, devise, or endowment made by any 
 43.36  person by will, deed, gift, or otherwise to or for the benefit, 
 44.1   support, or maintenance of any educational, charitable, or other 
 44.2   proper public purpose or function maintained by the department 
 44.3   of commerce.  In order to effect the purpose for which any gift, 
 44.4   bequest, devise, or endowment has been accepted, the 
 44.5   commissioner may sell it at a price fixed by the state board of 
 44.6   investment.  Any gift, bequest, devise, or endowment accepted by 
 44.7   the commissioner under this section is appropriated to the 
 44.8   commissioner to carry out the terms, conditions, or purposes of 
 44.9   the gift, bequest, devise, or endowment. 
 44.10     Sec. 2.  [216B.76] [MARKET POWER IN GENERATION.] 
 44.11     The commission and the department shall jointly monitor the 
 44.12  structure of the market for electric generation resources, and 
 44.13  the activities of participants in this market, for the 
 44.14  appropriate use of market power.  The commission shall take all 
 44.15  necessary steps to protect Minnesota consumers from the 
 44.16  inappropriate use of market power. 
 44.17     Sec. 3.  [216B.77] [REGIONAL OVERSIGHT.] 
 44.18     The commissioner shall develop and implement initiatives 
 44.19  with regulators in other states and regions to develop the 
 44.20  mechanisms and organizations necessary to ensure that the 
 44.21  interests of Minnesota consumers are advocated for and protected.
 44.22     Sec. 4.  [216B.78] [UTILITY RELATIONSHIPS WITH REGIONAL 
 44.23  INSTITUTIONS.] 
 44.24     Subdivision 1.  [CONTRACT APPROVAL.] No contract or 
 44.25  arrangement, including any general or continuing arrangement 
 44.26  between an electric utility and any regional institution seeking 
 44.27  to have operational control or influence over utility facilities 
 44.28  in Minnesota, such as an independent system operator or regional 
 44.29  transmission operator approved by the Federal Energy Regulatory 
 44.30  Commission, for (1) furnishing management, supervisory, 
 44.31  construction, engineering, accounting, legal, financial, or 
 44.32  similar services, (2) purchasing, selling, leasing, or 
 44.33  exchanging any property, right, or thing, or (3) furnishing any 
 44.34  service, property, right, or thing, is valid or effective unless 
 44.35  and until the contract or arrangement has received the written 
 44.36  approval of the commission.  Regular recurring transactions 
 45.1   under a general or continuing arrangement that has been approved 
 45.2   by the commission are valid if they are conducted in accordance 
 45.3   with the approved terms and conditions.  Every electric utility 
 45.4   shall file with the commission a verified copy of the contract 
 45.5   or arrangement, or a verified summary of the unwritten contract 
 45.6   or arrangement, and also of all the contracts and arrangements, 
 45.7   whether written or unwritten.  The commission shall approve the 
 45.8   contract or arrangement made or entered into after that date 
 45.9   only if it clearly appears and is established upon investigation 
 45.10  that it is reasonable and consistent with the public interest.  
 45.11  The burden of proof to establish the reasonableness of the 
 45.12  contract or arrangement is on the electric utility. 
 45.13     Subd. 2.  [CONTINUING AUTHORITY OF COMMISSION.] The 
 45.14  commission has continuing supervisory control over the terms and 
 45.15  conditions of the contracts and arrangements described in 
 45.16  subdivision 1 necessary to protect and promote the public 
 45.17  interest.  The commission has the same jurisdiction over the 
 45.18  modifications or amendment of contracts or arrangements as it 
 45.19  has over original contracts or arrangements.  The fact that the 
 45.20  commission has approved entry into contracts or arrangements 
 45.21  does not preclude disallowance or disapproval of payments made 
 45.22  under the contracts or arrangements, if upon actual experience 
 45.23  the commission determines that the payments provided for or made 
 45.24  were or are unreasonable. 
 45.25     Sec. 5.  [216B.79] [AUTHORITY TO ORDER FACILITY 
 45.26  CONSTRUCTION.] 
 45.27     The commission may order a public utility, municipal 
 45.28  utility, or rural electric cooperative association to construct 
 45.29  generation, distribution, or transmission facilities to ensure 
 45.30  that electric consumers in the state are provided with safe, 
 45.31  adequate, efficient, and reasonable service. 
 45.32     Sec. 6.  [272.028] [PERSONAL PROPERTY USED TO GENERATE 
 45.33  ELECTRICITY WHERE CONSTRUCTION STARTED AFTER JANUARY 1, 2001.] 
 45.34     Personal property used to generate electric power where 
 45.35  original construction of the generating plant started after 
 45.36  January 1, 2001, is exempt.  This exemption does not apply to 
 46.1   transformers, transmission lines, distribution lines, or any 
 46.2   other tools, implements, and machinery that are part of an 
 46.3   electric substation, wherever located. 
 46.4      In the case of a plant existing or under construction on 
 46.5   January 1, 2001, this exemption applies only if the nameplate 
 46.6   capacity of the plant is increased from that existing on January 
 46.7   1, 2001.  This exemption is computed by taking the increase in 
 46.8   megawatts over the total megawatt nameplate capacity after 
 46.9   construction is complete multiplied by the cost of all taxable 
 46.10  tools, implements, and machinery of the generating plant. 
 46.11     Sec. 7.  [EXPEDITED RULEMAKING.] 
 46.12     The department or the commission may adopt rules to 
 46.13  implement this act and may utilize expedited rulemaking where 
 46.14  necessary to ensure that rules, procedures, standards, or 
 46.15  criteria are in place in time to ensure reliable short-term and 
 46.16  long-term energy services. 
 46.17                             ARTICLE 5
 46.18                    SAFETY AND SERVICE STANDARDS
 46.19     Section 1.  [216B.80] [DEFINITIONS.] 
 46.20     Subdivision 1.  [SCOPE.] The terms used in this article 
 46.21  have the meanings given them in this section. 
 46.22     Subd. 2.  [AVERAGE NUMBER OF CUSTOMERS SERVED.] "Average 
 46.23  number of customers served" means the number of active, metered, 
 46.24  customer accounts available in a utility's 
 46.25  interruption-reporting database on the day that an interruption 
 46.26  occurs. 
 46.27     Subd. 3.  [CIRCUIT.] "Circuit" means a set of conductors 
 46.28  serving customer loads that are capable of being separated from 
 46.29  the serving substation automatically by a recloser, fuse, 
 46.30  sectionalizing equipment, and other devices. 
 46.31     Subd. 4.  [COMPONENT.] "Component" means a piece of 
 46.32  equipment, a line, a section of line, or a group of items that 
 46.33  is an entity for purposes of reporting, analyzing, and 
 46.34  predicting interruptions. 
 46.35     Subd. 5.  [CUSTOMER.] "Customer" means a separately metered 
 46.36  electrical service point for which a separate bill is rendered, 
 47.1   i.e., each meter represents a customer. 
 47.2      Subd. 6.  [CUSTOMER INTERRUPTION.] "Customer interruption" 
 47.3   means the loss of service due to a forced outage for more than 
 47.4   five minutes, for one or more customers, which is the result of 
 47.5   one or more component failures. 
 47.6      Subd. 7.  [CUSTOMERS' INTERRUPTIONS CAUSED BY POWER 
 47.7   RESTORATION PROCESS.] "Customers' interruptions caused by power 
 47.8   restoration process" means when customers lose power as a result 
 47.9   of the process of restoring power.  The duration of these 
 47.10  outages is included in the customer-minutes of interruption.  
 47.11  Only the customers affected by the power restoration outages 
 47.12  that were not affected by the original outage are added to the 
 47.13  number of customer interruptions.  
 47.14     Subd. 8.  [CUSTOMER-MINUTES OF 
 47.15  INTERRUPTION.] "Customer-minutes of interruption" means the 
 47.16  number of minutes of forced outage duration multiplied by the 
 47.17  number of customers affected. 
 47.18     Subd. 9.  [ELECTRIC DISTRIBUTION LINE.] "Electric 
 47.19  distribution line" means circuits operating at less than 40,000 
 47.20  volts. 
 47.21     Subd. 10.  [FORCED OUTAGE.] "Forced outage" means an outage 
 47.22  that cannot be deferred. 
 47.23     Subd. 11.  [MAJOR CATASTROPHIC EVENTS.] "Major catastrophic 
 47.24  events" means events that are beyond the utility's control that 
 47.25  result in widespread system damages causing customer 
 47.26  interruptions that affect at least ten percent of the customers 
 47.27  in the system or in an operating area or that result in 
 47.28  customers being without electric service for durations of at 
 47.29  least 24 hours. 
 47.30     Subd. 12.  [MAJOR STORM.] "Major storm" means a period of 
 47.31  severe adverse weather resulting in widespread system damage 
 47.32  causing customer interruptions that affect at least ten percent 
 47.33  of the customers on the system or in an operating area or that 
 47.34  result in customers being without electric service for durations 
 47.35  of at least 24 hours. 
 47.36     Subd. 13.  [MOMENTARY INTERRUPTION.] "Momentary 
 48.1   interruption" means an interruption of electric service with a 
 48.2   duration shorter than the time necessary to be classified as a 
 48.3   customer interruption. 
 48.4      Subd. 14.  [OPERATING AREA.] "Operating area" means a 
 48.5   geographical subdivision of each electric utility's service 
 48.6   territory that functions under the direction of a company office 
 48.7   and may be used for reporting interruptions under this article.  
 48.8   These areas may also be referred to as regions, divisions, or 
 48.9   districts. 
 48.10     Subd. 15.  [OUTAGE.] "Outage" means the failure of a power 
 48.11  system component that results in one or more customer 
 48.12  interruptions. 
 48.13     Subd. 16.  [OUTAGE DURATION.] "Outage duration" means the 
 48.14  one minute or greater period from the initiation of an 
 48.15  interruption to a customer until service has been restored to 
 48.16  that customer. 
 48.17     Subd. 17.  [PARTIAL CIRCUIT OUTAGE CUSTOMER 
 48.18  COUNT.] "Partial circuit outage customer count" means when only 
 48.19  part of a circuit experiences an outage, the number of customers 
 48.20  affected is estimated, unless an actual count is available.  
 48.21  When power is partially restored, the number of customers 
 48.22  restored is also estimated.  Most utilities use estimates based 
 48.23  on the portion of the circuit restored. 
 48.24     Subd. 18.  [PLANNED OUTAGES.] "Planned outages" means those 
 48.25  outages scheduled by the utility.  When customer service 
 48.26  interruptions are necessary, the utility shall notify affected 
 48.27  customers in advance.  These interruptions are sometimes 
 48.28  necessary to connect new customers or perform maintenance 
 48.29  activities safely.  They must not be included in the calculation 
 48.30  of reliability indexes. 
 48.31     Subd. 19.  [RELIABILITY.] "Reliability" means the degree to 
 48.32  which electric service is supplied without interruption. 
 48.33     Subd. 20.  [RELIABILITY INDEXES.] "Reliability indexes" 
 48.34  include the following performance indices for measuring 
 48.35  frequency and duration of service interruptions: 
 48.36     (a) The system average interruption frequency index is the 
 49.1   average number of interruptions per customer per year.  It is 
 49.2   determined by dividing the total annual number of customer 
 49.3   interruptions by the average number of customers served during 
 49.4   the year. 
 49.5      (b) The system average interruption duration index is the 
 49.6   average customer-minutes of interruption per customer.  It is 
 49.7   determined by dividing the annual sum of customer-minutes of 
 49.8   interruption by the average number of customers served during 
 49.9   the year. 
 49.10     (c) The customer average interruption duration index is the 
 49.11  average customer-minutes of interruption per customer 
 49.12  interruption.  It approximates the average length of time 
 49.13  required to complete service restoration.  It is determined by 
 49.14  dividing the annual sum of all customer-minutes of interruption 
 49.15  durations by the annual number of customer interruptions. 
 49.16     Sec. 2.  [216B.81] [RECORDING SERVICE INTERRUPTION 
 49.17  INDEXES.] 
 49.18     Subdivision 1.  [SYSTEM INTERRUPTION DATA.] Each electric 
 49.19  utility with 1,000 retail customers or more shall keep a record 
 49.20  of the necessary interruption data and calculate the system 
 49.21  average interruption frequency index, system average 
 49.22  interruption duration index, and customer average interruption 
 49.23  duration index of its system, and of each operating area, if 
 49.24  applicable, at the end of each calendar year for the previous 
 49.25  12-month period. 
 49.26     Subd. 2.  [CIRCUIT INTERRUPTION DATA.] Each utility also 
 49.27  shall, at the end of each calendar year, calculate the system 
 49.28  average interruption frequency index, system average 
 49.29  interruption duration index, and customer average interruption 
 49.30  duration index for each circuit in each operating area.  Each 
 49.31  circuit in each operating area must then be listed in order 
 49.32  separately according to its system average interruption 
 49.33  frequency index, its system average interruption duration index, 
 49.34  and its customer average interruption duration index, beginning 
 49.35  with the highest values for each index. 
 49.36     Sec. 3.  [216B.82] [ANNUAL REPORT.] 
 50.1      Subdivision 1.  [SUMMARY REPORT GENERALLY.] Beginning on 
 50.2   July 1, 2002, and by July 1 of every year thereafter, each 
 50.3   electric utility with 1,000 retail customers or more shall file 
 50.4   with the commission a report summarizing various measures of 
 50.5   reliability.  The form of the report is subject to review and 
 50.6   approval by the commission staff.  Names and numbers used to 
 50.7   identify operating areas or individual circuits may conform to 
 50.8   the utility's practice, but should allow ready identification of 
 50.9   the geographic location or the general area served.  Electronic 
 50.10  recording and reporting of the required data and information is 
 50.11  encouraged.  
 50.12     Subd. 2.  [INFORMATION REQUIRED.] (a) The report must 
 50.13  include at least the information described in paragraphs (b) to 
 50.14  (h). 
 50.15     (b) The report must provide an overall assessment of the 
 50.16  reliability of performance including the aggregate system 
 50.17  average interruption frequency index, system average 
 50.18  interruption duration index, and customer average interruption 
 50.19  duration index by system and each operating area, as applicable. 
 50.20     (c) The report must include a list of the worst performing 
 50.21  circuits based on system average interruption frequency index, 
 50.22  system average interruption duration index, and customer average 
 50.23  interruption duration index for the calendar year.  This portion 
 50.24  of the report must describe the actions that the utility has 
 50.25  taken or will take to remedy the conditions responsible for each 
 50.26  listed circuit's unacceptable performance.  The actions taken or 
 50.27  planned should be briefly described.  Target dates for 
 50.28  corrective actions must be included in the report.  When the 
 50.29  utility determines that actions on its part are unwarranted, its 
 50.30  report shall provide adequate justification for that conclusion. 
 50.31     (d) Utilities that use or prefer alternative criteria for 
 50.32  measuring individual circuit performance to those described in 
 50.33  paragraphs (b) and (c) and that are required by this section to 
 50.34  submit an annual report of reliability data, shall submit their 
 50.35  alternative listing of circuits along with the criteria used to 
 50.36  rank circuit performance. 
 51.1      (e) Information must be included with respect to any report 
 51.2   on the accomplishment of the improvements proposed in prior 
 51.3   reports for which completion has not been previously reported. 
 51.4      (f) The report must describe any new reliability or power 
 51.5   quality programs and changes that are made to existing programs. 
 51.6      (g) It must include a status report of any long-range 
 51.7   electric distribution plans. 
 51.8      (h) In addition to the information included in paragraph 
 51.9   (b), each utility shall report the following additional service 
 51.10  quality information: 
 51.11     (1) route miles of electric distribution line reconstructed 
 51.12  during the year, with separate totals for single- and 
 51.13  three-phase circuits provided; 
 51.14     (2) total route miles of electric distribution line in 
 51.15  service at year's end, segregated by voltage level; 
 51.16     (3) monthly average speed of answer for telephone calls 
 51.17  received regarding emergencies, outages, and customer billing 
 51.18  problems; 
 51.19     (4) the average number of calendar days a utility takes to 
 51.20  install and energize service to a customer site once it is ready 
 51.21  to receive service, with a separate average calculated for each 
 51.22  month, including all extensions energized during the calendar 
 51.23  month; 
 51.24     (5) the total number of written and telephone customer 
 51.25  complaints received in the areas of safety, customer billing, 
 51.26  outages, power quality, customer property damage, and other 
 51.27  areas, by month filed; 
 51.28     (6) total annual tree-trimming budget and actual expenses; 
 51.29  and 
 51.30     (7) total annual projected and actual miles of tree-trimmed 
 51.31  distribution line. 
 51.32     Sec. 4.  [216B.83] [INITIAL HISTORICAL RELIABILITY 
 51.33  PERFORMANCE REPORT.] 
 51.34     (a) Each electric utility with 1,000 retail customers or 
 51.35  more that has historically used measures of system, operating 
 51.36  area, and circuit reliability performance shall initially submit 
 52.1   annual system average interruption frequency index, system 
 52.2   average interruption duration index, and customer average 
 52.3   interruption duration index data for the previous three years.  
 52.4   Those utilities that have this data for some time period less 
 52.5   than three years shall submit data for those years it is 
 52.6   available. 
 52.7      (b) Those utilities whose historical reliability 
 52.8   performance data is similar or related to those measures listed 
 52.9   in paragraph (a), but differs due to how the parameters are 
 52.10  defined or calculated, shall submit the data it has and explain 
 52.11  any material differences from the prescribed indices.  After the 
 52.12  effective date of this section, utilities shall modify their 
 52.13  reliability performance measures to conform to those specified 
 52.14  in sections 216B.80 to 216B.86 for purposes of consistent 
 52.15  reporting of comparable data in the future. 
 52.16     Sec. 5.  [216B.84] [INTERRUPTIONS OF SERVICE; RECORDS; 
 52.17  NOTICE.] 
 52.18     Subdivision 1.  [RECORDS.] (a) Each utility shall keep 
 52.19  records of all interruptions to service affecting the entire 
 52.20  distribution system of any single community or an important 
 52.21  division of a community, and include in the records each 
 52.22  interruption's location, date and time, and duration; the 
 52.23  approximate number of customers affected; the circuit or 
 52.24  circuits involved; and, when known, the cause of each 
 52.25  interruption. 
 52.26     (b) When complete distribution systems or portions of 
 52.27  communities have service furnished from unattended stations, 
 52.28  these records must be kept to the extent practicable.  The 
 52.29  record of unattended stations shall show interruptions that 
 52.30  require attention to restore service, with the estimated time of 
 52.31  interruption.  Breaker or fuse operations affecting service 
 52.32  should also be indicated even though duration of interruption 
 52.33  may not be known. 
 52.34     Subd. 2.  [NOTICE OF INTERRUPTIONS OF BULK POWER SUPPLY 
 52.35  FACILITIES.] (a) Each utility shall notify the commission of any 
 52.36  event described in paragraphs (b) to (f) involving any 
 53.1   generating unit or electric facilities operating at a nominal 
 53.2   voltage of 69 kilovolts or higher. 
 53.3      (b) Notice must be given for any interruption or loss of 
 53.4   service to customers for 15 minutes or more to aggregate firm 
 53.5   loads in excess of 200,000 kilowatts.  This notification must be 
 53.6   made by telephone as soon as practicable without unduly 
 53.7   interfering with service restoration and, in any event, within 
 53.8   one hour after the beginning of the interruption.  A confirming 
 53.9   written report must be submitted within two weeks. 
 53.10     (c) Any interruption or loss of service to customers for 15 
 53.11  minutes or more to aggregate firm loads exceeding the lesser of 
 53.12  100,000 kilowatts or one-half of the current annual system peak 
 53.13  load and not required to be reported under paragraph (b) must be 
 53.14  reported to the commission.  This notification must be made by 
 53.15  telephone no later than the beginning of the commission's next 
 53.16  regular work day after the interruption occurred.  A confirming 
 53.17  written report must be submitted within two weeks. 
 53.18     (d) A utility shall notify the commission of any decision 
 53.19  to issue a public request for reduction in use of electricity.  
 53.20  Notification of this decision must be made by telephone at the 
 53.21  time of issuing the request.  A confirming written report must 
 53.22  be submitted within two weeks. 
 53.23     (e) An action to reduce firm customer loads by reduction of 
 53.24  voltage for reasons of maintaining adequacy of bulk electric 
 53.25  power supply must be reported to the commission.  Notification 
 53.26  of this action must be made by telephone at the time of taking 
 53.27  the action.  A confirming written report must be submitted 
 53.28  within two weeks. 
 53.29     (f) The utility shall notify the commission of any action 
 53.30  to reduce firm customer loads by manual switching, operation of 
 53.31  automatic load-shedding devices, or any other means for reasons 
 53.32  of maintaining adequacy of bulk electric power supply.  
 53.33  Notification of this action must be made by telephone at the 
 53.34  time of taking the action. 
 53.35     Subd. 3.  [NOTICE OF OTHER INTERRUPTIONS OF POWER.] (a) 
 53.36  Each utility shall notify the commission of service 
 54.1   interruptions not involving bulk power supply facilities in 
 54.2   accordance with paragraph (b). 
 54.3      (b) Interruptions of 60 minutes or more to an entire 
 54.4   distribution substation bus or entire feeder serving either 500 
 54.5   or more customers or entire cities or villages having 200 or 
 54.6   more customers must be reported within two weeks by written 
 54.7   report. 
 54.8      Subd. 4.  [INFORMATION REQUIRED.] The written reports 
 54.9   required in subdivisions 2 and 3 must include the date, time, 
 54.10  duration, general location, approximate number of customers 
 54.11  affected, identification of circuit or circuits involved, and, 
 54.12  when known, the cause of the interruption.  When extensive 
 54.13  interruptions occur, as from a storm, a narrative report 
 54.14  including the extent of the interruptions and system damage, 
 54.15  estimated number of customers affected, and a list of entire 
 54.16  communities interrupted may be submitted in lieu of reports of 
 54.17  individual interruptions. 
 54.18     Sec. 6.  [216B.85] [CUSTOMERS' COMPLAINTS.] 
 54.19     (a) Each utility shall investigate and keep a record of 
 54.20  complaints received by it from its customers in regard to 
 54.21  safety, service, or rates, and the operation of its system, with 
 54.22  appropriate response times designated for critical safety and 
 54.23  monetary loss situations.  The record must show the name and 
 54.24  address of the complainant, the date and nature of the 
 54.25  complaint, the priority assigned to the assistance, and its 
 54.26  disposition and the time and date of its disposition. 
 54.27     (b) Each utility also shall document all contacts and 
 54.28  action relative to deferred payment agreements and disputes. 
 54.29     Sec. 7.  [216B.86] [STANDARDS FOR DISTRIBUTION UTILITIES.] 
 54.30     (a) The commission shall adopt standards for safety, 
 54.31  reliability, and service quality for distribution utilities and 
 54.32  shall annually report on the aggregate performance of 
 54.33  Minnesota's distribution utilities relative to those standards. 
 54.34     (b) Reliability standards must be based on the system 
 54.35  average interruption frequency index, system average 
 54.36  interruption duration index, and customer average interruption 
 55.1   duration index measurement indices.  Service quality standards 
 55.2   must specify: 
 55.3      (1) average call center response time; 
 55.4      (2) customer disconnection rate; 
 55.5      (3) meter-reading frequency; 
 55.6      (4) complaint resolution response time; and 
 55.7      (5) service extension request response time. 
 55.8      (c) Minimum performance standards developed under this 
 55.9   section must treat similarly situated distribution systems 
 55.10  similarly and recognize differing characteristics of system 
 55.11  design and hardware. 
 55.12                             ARTICLE 6 
 55.13                       CONFORMING AMENDMENTS 
 55.14     Section 1.  Minnesota Statutes 2000, section 216B.16, 
 55.15  subdivision 6b, is amended to read: 
 55.16     Subd. 6b.  [ENERGY CONSERVATION IMPROVEMENT.] (a) Except as 
 55.17  otherwise provided in this subdivision, all investments and 
 55.18  expenses of a public utility as defined in section 216B.241, 
 55.19  subdivision 1, paragraph (e) (g), incurred in connection with 
 55.20  energy conservation improvements shall be recognized and 
 55.21  included by the commission in the determination of just and 
 55.22  reasonable rates as if the investments and expenses were 
 55.23  directly made or incurred by the utility in furnishing utility 
 55.24  service. 
 55.25     (b) After December 31, 1999, investments and expenses for 
 55.26  energy conservation improvements shall not be included by the 
 55.27  commission in the determination of just and reasonable electric 
 55.28  and gas rates for retail electric and gas service provided to 
 55.29  large electric customer facilities that have been exempted by 
 55.30  the commissioner of the department of public service pursuant to 
 55.31  section 216B.241, subdivision 1a, paragraph (b).  However, no 
 55.32  public utility shall be prevented from recovering its investment 
 55.33  in energy conservation improvements from all customers that were 
 55.34  made on or before December 31, 1999, in compliance with the 
 55.35  requirements of section 216B.241.  
 55.36     (c) The commission may permit a public utility to file rate 
 56.1   schedules providing for annual recovery of the costs of energy 
 56.2   conservation improvements.  These rate schedules may be 
 56.3   applicable to less than all the customers in a class of retail 
 56.4   customers if necessary to reflect the differing minimum spending 
 56.5   requirements of section 216B.241, subdivision 1a.  After 
 56.6   December 31, 1999, the commission shall allow a public utility, 
 56.7   without requiring a general rate filing under this section, to 
 56.8   reduce the electric and gas rates applicable to large electric 
 56.9   customer facilities that have been exempted by the commissioner 
 56.10  of the department of public service pursuant to section 
 56.11  216B.241, subdivision 1a, paragraph (b), by an amount that 
 56.12  reflects the elimination of energy conservation improvement 
 56.13  investments or expenditures for those facilities required on or 
 56.14  before December 31, 1999.  In the event that the commission has 
 56.15  set electric or gas rates based on the use of an accounting 
 56.16  methodology that results in the cost of conservation 
 56.17  improvements being recovered from utility customers over a 
 56.18  period of years, the rate reduction may occur in a series of 
 56.19  steps to coincide with the recovery of balances due to the 
 56.20  utility for conservation improvements made by the utility on or 
 56.21  before December 31, 1999.  
 56.22     Sec. 2.  Minnesota Statutes 2000, section 216B.1621, 
 56.23  subdivision 2, is amended to read: 
 56.24     Subd. 2.  [COMMISSION APPROVAL.] (a) The commission shall 
 56.25  approve an agreement under this section upon finding that: 
 56.26     (1) the proposed electric service power generation facility 
 56.27  could reasonably be expected to qualify for a market value 
 56.28  exclusion under section 272.0211; 
 56.29     (2) the public utility has a contractual option to purchase 
 56.30  electric power from the proposed facility; and 
 56.31     (3) the public utility can use the output from the proposed 
 56.32  facility to meet its future need for power as demonstrated in 
 56.33  the most recent resource plan filed with and approved by the 
 56.34  commission under section 216B.2422. 
 56.35     (b) Sections 216B.03, 216B.05, 216B.06, 216B.07, 216B.16, 
 56.36  216B.162, and 216B.23 do not apply to an agreement under this 
 57.1   section. 
 57.2      Sec. 3.  Minnesota Statutes 2000, section 216B.164, 
 57.3   subdivision 4, is amended to read: 
 57.4      Subd. 4.  [PURCHASES; WHEELING; COSTS.] (a) Except as 
 57.5   otherwise provided in paragraph (c), this subdivision shall 
 57.6   apply to all qualifying facilities having 40-kilowatt capacity 
 57.7   or more as well as qualifying facilities as defined in 
 57.8   subdivision 3 which elect to be governed by its provisions.  
 57.9      (b) The utility to which the qualifying facility is 
 57.10  interconnected shall purchase all energy and capacity made 
 57.11  available by the qualifying facility.  The qualifying facility 
 57.12  shall be paid the utility's full avoided capacity and energy 
 57.13  costs as negotiated by the parties, as set by the commission, or 
 57.14  as determined through competitive bidding approved by the 
 57.15  commission.  The full avoided capacity and energy costs to be 
 57.16  paid a qualifying facility that generates electric power by 
 57.17  means of a renewable energy source are the utility's least cost 
 57.18  renewable energy facility or the bid of a competing supplier of 
 57.19  a least cost renewable energy facility, whichever is lower, 
 57.20  unless the commission's resource plan order, under section 
 57.21  216B.2422, subdivision 2, provides that the use of a renewable 
 57.22  resource to meet the identified capacity need is not in the 
 57.23  public interest.  
 57.24     (c) For all qualifying facilities having 30-kilowatt 
 57.25  capacity or more, the utility shall, at the qualifying 
 57.26  facility's or the utility's request, provide wheeling or 
 57.27  exchange agreements wherever practicable to sell the qualifying 
 57.28  facility's output to any other Minnesota utility having 
 57.29  generation expansion anticipated or planned for the ensuing ten 
 57.30  years.  The commission shall establish the methods and 
 57.31  procedures to insure that except for reasonable wheeling charges 
 57.32  and line losses, the qualifying facility receives the full 
 57.33  avoided energy and capacity costs of the utility ultimately 
 57.34  receiving the output.  
 57.35     (d) The commission shall set rates for electricity 
 57.36  generated by renewable energy. 
 58.1      Sec. 4.  Minnesota Statutes 2000, section 216B.2421, 
 58.2   subdivision 1, is amended to read: 
 58.3      Subdivision 1.  [APPLICABILITY.] The definition in this 
 58.4   section applies to this section and sections 216B.2422 and 
 58.5   section 216B.243. 
 58.6      Sec. 5.  Minnesota Statutes 2000, section 216B.2423, 
 58.7   subdivision 2, is amended to read: 
 58.8      Subd. 2.  [RESOURCE PLANNING MANDATE.] The public utilities 
 58.9   commission shall order a public utility subject to subdivision 
 58.10  1, to construct and operate, purchase, or contract to purchase 
 58.11  an additional 400 megawatts of electric energy installed 
 58.12  capacity generated by wind energy conversion systems by December 
 58.13  31, 2002, subject to resource planning and least cost planning 
 58.14  requirements in section 216B.2422. 
 58.15     Sec. 6.  Minnesota Statutes 2000, section 216B.243, 
 58.16  subdivision 3, is amended to read: 
 58.17     Subd. 3.  [SHOWING REQUIRED FOR CONSTRUCTION.] No proposed 
 58.18  large energy facility shall be certified for construction unless 
 58.19  the applicant can show that demand for electricity cannot be met 
 58.20  more cost-effectively through energy conservation and 
 58.21  load-management measures and unless the applicant has otherwise 
 58.22  justified its need.  In assessing need, the commission shall 
 58.23  evaluate: 
 58.24     (1) the accuracy of the long-range energy demand forecasts 
 58.25  on which the necessity for the facility is based; 
 58.26     (2) the effect of existing or possible energy conservation 
 58.27  programs under sections 216C.05 to 216C.30 and this section or 
 58.28  other federal or state legislation on long-term energy demand; 
 58.29     (3) the relationship of the proposed facility to overall 
 58.30  state energy needs, as described in the most recent state energy 
 58.31  policy and conservation report prepared under section 216C.18; 
 58.32     (4) promotional activities that may have given rise to the 
 58.33  demand for this facility; 
 58.34     (5) socially beneficial uses of the output of this 
 58.35  facility, including its uses to protect or enhance environmental 
 58.36  quality; 
 59.1      (6) the effects of the facility in inducing future 
 59.2   development; 
 59.3      (7) possible alternatives for satisfying the energy demand 
 59.4   including but not limited to potential for increased efficiency 
 59.5   of existing energy generation facilities; 
 59.6      (8) the policies, rules, and regulations of other state and 
 59.7   federal agencies and local governments; and 
 59.8      (9) any feasible combination of energy conservation 
 59.9   improvements, required under section 216B.241, that can (i) 
 59.10  replace part or all of the energy to be provided by the proposed 
 59.11  facility, and (ii) compete with it economically. 
 59.12     Sec. 7.  Minnesota Statutes 2000, section 216C.17, 
 59.13  subdivision 3, is amended to read: 
 59.14     Subd. 3.  [DUPLICATION.] The commissioner shall, to the 
 59.15  maximum extent feasible, provide that forecasts required under 
 59.16  this section be consistent with material required by other state 
 59.17  and federal agencies in order to prevent unnecessary 
 59.18  duplication.  Electric utilities submitting advance forecasts as 
 59.19  part of an integrated resource plan filed pursuant to section 
 59.20  216B.2422 and public utilities commission rules are excluded 
 59.21  from the annual reporting requirement in subdivision 2.