1.1                          A bill for an act 
  1.2             relating to energy; enacting the Energy Reliability 
  1.3             and Affordability Act; making conforming and 
  1.4             clarifying changes; amending Minnesota Statutes 2000, 
  1.5             sections 216A.07, subdivision 3; 216B.03; 216B.16, 
  1.6             subdivisions 1 and 6b; 216B.162, subdivision 8; 
  1.7             216B.164, subdivisions 3 and 6; 216B.243, subdivision 
  1.8             3; 216C.09; and 216C.18, subdivision 1a; proposing 
  1.9             coding for new law as Minnesota Statutes, chapter 
  1.10            216E; repealing Minnesota Statutes 2000, section 
  1.11            216B.241; Minnesota Rules, parts 7820.1800; 7820.1900; 
  1.12            7820.2000; 7820.2200; and 7820.2300. 
  1.13  BE IT ENACTED BY THE LEGISLATURE OF THE STATE OF MINNESOTA: 
  1.14                             ARTICLE 1
  1.15                CITATION, FINDINGS, AND DEFINITIONS 
  1.16     Section 1.  [SHORT TITLE.] 
  1.17     This act may be cited as the "Energy Reliability and 
  1.18  Affordability Act of 2001." 
  1.19     Sec. 2.  [LEGISLATIVE FINDINGS.] 
  1.20     The legislature finds and declares that energy is a basic 
  1.21  necessity and is essential for the safety, health, and welfare 
  1.22  of the state's citizens and economy.  The legislature also finds 
  1.23  that it is in the public interest to: 
  1.24     (1) assure that all citizens have access to basic energy 
  1.25  requirements; 
  1.26     (2) ensure that the state's energy supply is reliable, 
  1.27  safe, affordable, efficient, and environmentally sound; 
  1.28     (3) reduce future energy needs; 
  1.29     (4) limit susceptibility to energy price fluctuations; 
  2.1      (5) reduce emissions released into the environment while 
  2.2   maintaining economic growth and security; 
  2.3      (6) establish programs that enable residential customers 
  2.4   with low incomes to afford and manage basic energy services; 
  2.5      (7) expand protections to assure all residential customers 
  2.6   are able to maintain energy services; 
  2.7      (8) ensure the integrity, reliability, and safety of the 
  2.8   electric system; 
  2.9      (9) ensure adequate investment in, and regular inspection 
  2.10  and maintenance of, power plants and utility facilities; and 
  2.11     (10) maintain and expand training required to guarantee a 
  2.12  skilled utility workforce. 
  2.13     Sec. 3.  [216E.01] [DEFINITIONS.] 
  2.14     Subdivision 1.  [SCOPE.] For purposes of this chapter, the 
  2.15  terms defined in this subdivision have the meanings given them. 
  2.16  The definitions in chapters 216A, 216B, and 216C also apply to 
  2.17  terms not defined in this section. 
  2.18     Subd. 2.  [ADMINISTRATOR.] "Administrator" means the 
  2.19  department of economic security. 
  2.20     Subd. 3.  [AFFILIATE.] "Affiliate" means (1) a subsidiary, 
  2.21  (2) any company or corporation owned or effectively controlled 
  2.22  by a public utility or a subsidiary, or (3) any company or 
  2.23  corporation owned or effectively controlled by the same company 
  2.24  or corporation that owns or effectively controls a public 
  2.25  utility. 
  2.26     Subd 4.  [ARREARS.] "Arrears" means amounts owed for 
  2.27  utility service that are more than 60 days past due. 
  2.28     Subd. 5.  [BOARD.] "Board" means the energy efficiency 
  2.29  advisory board. 
  2.30     Subd. 6.  [BUSINESS DAY.] "Business day" means Mondays 
  2.31  through Fridays, excluding legal holidays. 
  2.32     Subd. 7.  [CALENDAR DAY.] "Calendar day" means Mondays 
  2.33  through Sundays, excluding legal holidays. 
  2.34     Subd. 8.  [COMMISSION.] "Commission" means the public 
  2.35  utilities commission. 
  2.36     Subd. 9.  [COMMISSIONER.] "Commissioner" means the 
  3.1   commissioner of the department of commerce. 
  3.2      Subd. 10.  [CONTRACTOR.] "Contractor" means an organization 
  3.3   selected by the department to deliver energy efficiency 
  3.4   programs.  A distribution utility may be a contractor. 
  3.5      Subd. 11.  [COST-EFFECTIVE.] "Cost-effective" means that 
  3.6   the projected total cost of an energy conservation improvement 
  3.7   is less than the projected present value of the energy and 
  3.8   demand savings resulting from the improvement. 
  3.9      Subd. 12.  [CUSTOMER.] "Customer" means the person in whose 
  3.10  name residential utility service is rendered. 
  3.11     Subd. 13.  [DEPARTMENT.] "Department" means the department 
  3.12  of commerce. 
  3.13     Subd. 14.  [DIRECT ACCESS SUPPLIER.] "Direct access 
  3.14  supplier" means a private entity that sells power or bundled 
  3.15  electric services but does not own or control transmission or 
  3.16  distribution lines. 
  3.17     Subd. 15.  [DISTRIBUTION UTILITY.] "Distribution utility" 
  3.18  means a public utility, municipality, or cooperative electric 
  3.19  association that conveys electricity or natural gas, either 
  3.20  directly or indirectly, to retail customers in the state. 
  3.21     Subd. 16.  [ELECTRIC GENERATING FACILITY.] "Electric 
  3.22  generating facility" means a single electric generating unit or 
  3.23  group of units on the same location, or group of units commonly 
  3.24  owned by a retail electric company with a nameplate capacity of 
  3.25  50 megawatts or more that utilizes coal as its primary fuel 
  3.26  input, that generates electric energy for compensation, and that 
  3.27  is owned or operated by a person in this state, including a 
  3.28  municipal corporation or electric cooperative.  Electric 
  3.29  generating facility includes units built on, before, or after 
  3.30  the effective date of this chapter. 
  3.31     Subd. 17.  [END-USER.] "End-user" means an entity located 
  3.32  in the state that purchases electricity based on metered use but 
  3.33  does not resell electricity based on metered use. 
  3.34     Subd. 18.  [ENERGY BURDEN.] "Energy burden" means the 
  3.35  percentage of household income devoted to energy bills. 
  3.36     Subd. 19.  [ENERGY UNIT.] "Energy unit" means a unit in 
  4.1   this state that is engaged in activities related to the 
  4.2   production, generation, transmission, or distribution of 
  4.3   electricity or natural gas. 
  4.4      Subd. 20.  [FACILITIES.] "Facilities" means the tangible 
  4.5   and intangible property, without limitation, that is owned, 
  4.6   operated, leased, licensed, used, controlled, or supplied for or 
  4.7   by a public utility for generating, transmitting, or 
  4.8   distributing electricity or natural gas. 
  4.9      Subd. 21.  [FEDERAL ENERGY ASSISTANCE PROGRAM.] "Federal 
  4.10  energy assistance program" means the federal program codified at 
  4.11  United States Code, title 42, sections 8621 to 8629. 
  4.12     Subd. 22.  [FEDERAL WEATHERIZATION ASSISTANCE 
  4.13  PROGRAM.] "Federal weatherization assistance program" refers to 
  4.14  the federal program codified at United States Code, title 42, 
  4.15  sections 6862 to 6873. 
  4.16     Subd. 23.  [FUND.] "Fund" means the public benefits fund. 
  4.17     Subd. 24.  [LOW-INCOME CUSTOMER.] "Low-income customer" 
  4.18  means a customer of a public utility, municipality, or 
  4.19  cooperative electric association who is income eligible for the 
  4.20  federal Low-Income Home Energy Assistance Program, codified at 
  4.21  United States Code, title 42, sections 8621 to 8629. 
  4.22     Subd. 25.  [MARKET SECTOR.] "Market sector" means the 
  4.23  residential, commercial, or industrial class of electric 
  4.24  customers. 
  4.25     Subd. 26.  [MEDICALLY NECESSARY EQUIPMENT.] "Medically 
  4.26  necessary equipment" means equipment that operates on utility 
  4.27  service that without such operation a person's life would be in 
  4.28  jeopardy. 
  4.29     Subd. 27.  [NONBYPASSABLE SURCHARGE.] "Nonbypassable 
  4.30  surcharge" means a charge payable by an end-user of a public 
  4.31  utility, a municipality, or a cooperative electric association. 
  4.32     Subd. 28.  [NONUTILITY AFFILIATE.] "Nonutility affiliate" 
  4.33  means a company in a holding company system that is not a public 
  4.34  utility. 
  4.35     Subd. 29.  [PAYMENT AGREEMENT.] "Payment agreement" means 
  4.36  an agreement between a customer and a utility to pay utility 
  5.1   charges over time in installments. 
  5.2      Subd. 30.  [PAYMENT-TROUBLED CUSTOMERS.] "Payment-troubled 
  5.3   customers" means low-income customers who are presently 
  5.4   disconnected or who have been disconnected for nonpayment at 
  5.5   least once in the previous year or who regularly demonstrate an 
  5.6   inability to pay their entire utility bill or whose energy 
  5.7   burden exceeds two times the average residential energy burden. 
  5.8      Subd. 31.  [RENEWABLE ENERGY CREDIT.] "Renewable energy 
  5.9   credit" means a tradable certificate of proof that one 
  5.10  kilowatt-hour of renewable energy resource electricity, from a 
  5.11  facility placed in operation after December 31, 2002, was either 
  5.12  (1) sold to or generated by a retail electricity supplier that 
  5.13  sells to end-users, (2) sold to a utility distribution company 
  5.14  that sells to end-users, or (3) produced by a self-generator.  
  5.15  Renewable energy credits are denominated in kilowatt-hours. 
  5.16     Subd. 32.  [RENEWABLE ENERGY RESOURCE.] "Renewable energy 
  5.17  resource" means a technology that exclusively relies on an 
  5.18  energy source that is naturally and sustainably regenerated over 
  5.19  a short time and derived directly from the sun, indirectly from 
  5.20  the sun, or from moving water or other natural movements and 
  5.21  mechanisms of the environment.  Renewable energy technologies 
  5.22  include solar, wind, hydroelectric with a capacity of less than 
  5.23  60 megawatts, or solid fuel biomass farm-grown as a dedicated 
  5.24  energy crop.  A renewable energy technology does not rely on 
  5.25  energy resources derived from fossil fuels, waste products from 
  5.26  fossil fuels, or waste products from inorganic sources with the 
  5.27  exception of landfill gas. 
  5.28     Subd. 33.  [RENEWABLES PORTFOLIO STANDARD.] "Renewables 
  5.29  portfolio standard" means the percentage of electric power 
  5.30  consumed in the state that must be derived from renewable energy 
  5.31  resources. 
  5.32     Subd. 34.  [RETAIL ELECTRICITY SUPPLIER.] "Retail 
  5.33  electricity supplier" means an entity that sells electric power 
  5.34  not for resale to an end-user, including but not limited to 
  5.35  electricity providers that are affiliates or generating 
  5.36  companies of public utilities, municipalities, electric 
  6.1   cooperative associations, local governments, special districts, 
  6.2   or direct access suppliers. 
  6.3      Subd. 35.  [SELF-GENERATOR.] "Self-generator" means a 
  6.4   grid-connected entity located in the state that generates power 
  6.5   from an owned or leased facility for its own consumption. 
  6.6      Subd. 36.  [UNDERCHARGE.] "Undercharge" means a charge 
  6.7   rendered for utility service previously rendered but not 
  6.8   previously billed, not billed in full, or billed at an amount 
  6.9   less than actual usage. 
  6.10     Subd. 37.  [UNIVERSAL SERVICE PROGRAM.] "Universal service 
  6.11  program" means bill payment and conservation assistance provided 
  6.12  to low-income customers. 
  6.13                             ARTICLE 2
  6.14                       RELIABILITY ASSESSMENT
  6.15     Section 1.  [216E.02] [RELIABILITY ASSESSMENT.] 
  6.16     Subdivision 1.  [REPORTING.] Annually, the commission shall 
  6.17  require distribution utilities, except natural gas distribution 
  6.18  utilities, to report on operating and planning reserves, 
  6.19  available transmission capacity, outages of major generation 
  6.20  units and feeders of distribution and transmissions facilities, 
  6.21  the adequacy of stock and equipment, and any other information 
  6.22  necessary to assess the current and future reliability of 
  6.23  electric service in this state.  Distribution utilities that are 
  6.24  currently required to file resource plans may submit updates, if 
  6.25  applicable. 
  6.26     Subd. 2.  [ASSESSMENT AND REPORT TO LEGISLATURE.] By 
  6.27  January 31 of each year beginning in 2002, the commission shall 
  6.28  assess and report to the legislature the status of the 
  6.29  reliability of electric service in the state and make 
  6.30  recommendations, if applicable, for legislative action. 
  6.31     Subd. 3.  [AUTHORITY TO ENSURE ADEQUATE INVESTMENT.] The 
  6.32  commission has the authority to ensure that distribution 
  6.33  utilities are making adequate investment in plants and other 
  6.34  facilities used in the production, transmission, or distribution 
  6.35  of electricity and are conducting preventive maintenance with 
  6.36  respect to those plants and facilities that is sufficient to 
  7.1   guarantee reliable electric service.  The commission may order a 
  7.2   distribution utility to construct generation, distribution, or 
  7.3   transmission facilities to ensure that electric consumers in the 
  7.4   state are provided with safe, adequate, reliable, efficient, and 
  7.5   reasonable electric service. 
  7.6                              ARTICLE 3
  7.7                         PUBLIC BENEFITS FUND
  7.8      Section 1.  [216E.03] [PUBLIC BENEFITS FUND.] 
  7.9      Subdivision 1.  [ESTABLISHMENT.] The public benefits fund 
  7.10  is established for funding energy efficiency and for low-income 
  7.11  bill payment and conservation assistance. 
  7.12     Subd. 2.  [FUNDING LEVEL.] Every distribution utility shall 
  7.13  collect a nonbypassable surcharge from all end-use customers.  
  7.14  The surcharge must be a volumetric charge on sales of 
  7.15  electricity and natural gas of 1.89 mills per kilowatt-hour 
  7.16  (kWh) for electricity and $0.095 per thousand cubic feet for 
  7.17  natural gas.  Except as otherwise provided, the provisions of 
  7.18  this section are not applicable to a sale of electricity by a 
  7.19  utility to another utility for resale. 
  7.20     Subd. 3.  [REMITTANCE.] By February 1 of each year, the 
  7.21  commission shall require every distribution utility to remit to 
  7.22  the department of revenue amounts collected under the surcharge 
  7.23  for the sales occurring in the previous year.  Interest on the 
  7.24  amount accumulated in the fund accrues to the fund.  The 
  7.25  department of revenue shall disperse proceeds of the fund as 
  7.26  dictated by the commission in accordance with this chapter. 
  7.27     Subd. 4.  [ALLOCATION OF FUND PROCEEDS.] The commission 
  7.28  shall disperse the proceeds of the fund as follows: 
  7.29     (1) 70 percent of the funds collected from electric sales 
  7.30  and 20 percent of the funds collected from natural gas sales 
  7.31  must be allocated to energy efficiency programs.  Funds to 
  7.32  conduct the energy efficiency program must be allocated 
  7.33  proportionally according to contributions made by service 
  7.34  territory and customer class; and 
  7.35     (2) 30 percent of the funds collected from electric sales 
  7.36  and 80 percent of the funds collected from natural gas must be 
  8.1   allocated to low-income programs. 
  8.2      Sec. 2.  [216E.04] [ENERGY EFFICIENCY PROGRAM.] 
  8.3      Subdivision 1.  [ESTABLISHMENT.] An energy efficiency 
  8.4   program is established.  The commission and the department shall 
  8.5   perform the duties assigned to them as specified in this chapter.
  8.6      Subd. 2.  [CONTRACTOR.] The commissioner shall select one 
  8.7   or more contractors to carry out the duties as specified in this 
  8.8   chapter.  All contractors must be selected through a competitive 
  8.9   bidding process.  To fulfill the obligations of the contract, 
  8.10  the contractor may: 
  8.11     (1) subcontract with a political subdivision, a nonprofit 
  8.12  or community organization, or a distribution utility to 
  8.13  implement various projects; and 
  8.14     (2) provide grants to any person to conduct research and 
  8.15  development projects in accordance with this section. 
  8.16     Subd. 3.  [ELIGIBILITY.] The contractor may be a private 
  8.17  company, not-for-profit organization, or distribution utility. 
  8.18     Subd. 4.  [CONTRACT TERM.] The contract period must be 
  8.19  three years. 
  8.20     Subd. 5.  [DUTIES.] The contractor shall administer, 
  8.21  implement, and deliver energy efficiency projects to a sector, 
  8.22  region, or area as determined by the department.  In carrying 
  8.23  out these projects, the contractor shall: 
  8.24     (1) develop and maintain reliable administrative and 
  8.25  monitoring procedures that will allow evaluation of the 
  8.26  effectiveness of its efforts, provide a basis for project 
  8.27  modifications, and document its accomplishments; 
  8.28     (2) develop, implement, and maintain the necessary 
  8.29  budgeting, invoicing, expenditure approval, payroll, and 
  8.30  financial accounting systems to review, approve, and track 
  8.31  budgets, invoices, and payments to subcontractors, project 
  8.32  implementers, employees, and, in some cases, customers; 
  8.33     (3) develop and maintain systems that provide appropriate 
  8.34  protections in the collection, processing, storage, and 
  8.35  retrieval of information that is customer-specific or could 
  8.36  provide an unfair competitive advantage to an entity delivering 
  9.1   services other than energy efficiency projects.  Accordingly, 
  9.2   the contractor shall develop and maintain a process with clearly 
  9.3   defined standards and safeguards to govern the sharing of that 
  9.4   information with subcontractors, the commission, the department, 
  9.5   and distribution utilities, to ensure customer confidentiality 
  9.6   is maintained and entities are not provided an unfair 
  9.7   competitive advantage; 
  9.8      (4) provide information and documentation required by the 
  9.9   commission, department, or board; 
  9.10     (5) keep all invoicing data along with proper supporting 
  9.11  documentation and make that information available to the 
  9.12  commission, the department, or the board; 
  9.13     (6) collect and electronically compile data needed to 
  9.14  monitor, assess, and evaluate its project performance, to report 
  9.15  on its activities, and to improve the design and delivery of the 
  9.16  energy efficiency program; 
  9.17     (7) allocate no more than ten percent of the total amount 
  9.18  annually on research and development projects and evaluations; 
  9.19     (8) act in an independent capacity and not as an officer or 
  9.20  employee of the state; and 
  9.21     (9) indemnify, defend, and hold harmless the state and its 
  9.22  officers and employees from liability and any claims, suits, 
  9.23  judgments, and damages arising as a result of the contractor's 
  9.24  acts or omissions in the performance of duties. 
  9.25     Subd. 6.  [REPORTS.] The contractor shall prepare and 
  9.26  submit quarterly and annual reports, which must include: 
  9.27     (1) actual administrative and project expenditures and 
  9.28  commitments, compared to the budget amounts; 
  9.29     (2) kilowatt-hour (kWh) and kilowatt (kW) savings 
  9.30  estimates, participation rates, and other performance metrics, 
  9.31  compared to goals and targets, and explanation of any 
  9.32  significant differences in these items; 
  9.33     (3) any proposed or actual changes to project scope, 
  9.34  designs, or implementation; 
  9.35     (4) methods and results of the contractor's tracking and 
  9.36  monitoring of activities; and 
 10.1      (5) any other information required by the commission or the 
 10.2   department. 
 10.3      Subd. 7.  [ENERGY EFFICIENCY ADVISORY BOARD.] (a) An energy 
 10.4   efficiency advisory board is established, with members appointed 
 10.5   by the commission to serve a period of four years each, 
 10.6   commencing July 1, 2001. 
 10.7      (b) Members are entitled to receive a per diem at a rate 
 10.8   established by the department for meeting attendance, project 
 10.9   review, and other duties required.  Members are also entitled to 
 10.10  reimbursement for all actual and necessary expenses incurred in 
 10.11  the performance of their official duties. 
 10.12     (c) The board consists of eight members, including one 
 10.13  engineer or research scientist who is trained in or familiar 
 10.14  with energy issues and who possesses knowledge regarding energy 
 10.15  efficiency technologies; one member each from the department, a 
 10.16  nonprofit consumer organization, and a nonprofit community 
 10.17  organization; two members from nonprofit environmental 
 10.18  organizations; and two members from distribution utilities. 
 10.19     (d) The commission shall appoint two members for terms 
 10.20  expiring July 1, 2003, three members for terms expiring July 1, 
 10.21  2004, and three members for terms expiring July 1, 2005.  
 10.22  Persons appointed for full terms as successors to these initial 
 10.23  members shall serve for terms of four years each commencing on 
 10.24  July 1.  A majority of the members constitute a quorum for the 
 10.25  transaction of any business or the exercise of any power of the 
 10.26  energy efficiency advisory board.  The commission may remove any 
 10.27  member for neglect of duty, misconduct in office, or other 
 10.28  reason determined by the commission. 
 10.29     (e) By January 1, 2002, the board shall develop criteria 
 10.30  for the selection of a contractor, who must: 
 10.31     (1) present specific and measurable goals for achieving the 
 10.32  bidder's proposed objectives in each market sector; and 
 10.33     (2) present a description of the bidder's proven capability 
 10.34  to deliver energy efficiency programs effectively and 
 10.35  demonstrated capacity to design and implement innovative 
 10.36  approaches to securing energy efficiency improvements. 
 11.1   The board shall review all bids and shall make a recommendation 
 11.2   to the department for the selection of a contractor.  The board 
 11.3   shall review contractor project evaluations and may make 
 11.4   recommendations relating to new programs or improvements of 
 11.5   existing project targets. 
 11.6      Subd. 8.  [DEPARTMENT DUTIES.] In connection with the 
 11.7   energy efficiency program, the department shall: 
 11.8      (1) manage the fund; 
 11.9      (2) issue, upon development of the selection criteria 
 11.10  developed by the board, a request for proposal to bid to become 
 11.11  a contractor; 
 11.12     (3) select, after review of the board's recommendations, a 
 11.13  contractor; 
 11.14     (4) oversee programs delivered by the contractor; 
 11.15     (5) make changes to the contractor's programs to make them 
 11.16  more cost-effective; 
 11.17     (6) consider projects suggested by an outside source, 
 11.18  including a political subdivision or a nonprofit or community 
 11.19  organization; 
 11.20     (7) consider petitions to modify or revoke a contractor 
 11.21  decision concerning a project that are submitted by a utility, a 
 11.22  political subdivision, a private company, a nonprofit or 
 11.23  community organization that has suggested a program, the 
 11.24  residential utility division of the office of the attorney 
 11.25  general, or a customer; 
 11.26     (8) modify or revoke a contractor decision upon the 
 11.27  determination that the project is not cost-effective, has a 
 11.28  long-range adverse effect on one or more classes of customers, 
 11.29  or is otherwise not in the public interest; 
 11.30     (9) reject a petition to modify or revoke a contractor's 
 11.31  decision that, on its face, fails to make a reasonable argument 
 11.32  that a program is not in the public interest; and 
 11.33     (10) direct an independent evaluation of the contractor's 
 11.34  projects by market sector on the basis of cost-effectiveness and 
 11.35  the reliability of technologies employed. 
 11.36     Subd. 9.  [DUTIES OF COMMISSION.] The commission shall: 
 12.1      (1) review and approve or reject the department's 
 12.2   recommendation for a contractor.  If the commission rejects the 
 12.3   contractor recommended by the department, it may select its own 
 12.4   contractor; and 
 12.5      (2) act as the final authority over all matters regarding 
 12.6   the fund. 
 12.7      Subd. 10.  [PROJECTS.] (a) Projects conducted under the 
 12.8   energy efficiency program must consist of energy conservation 
 12.9   improvements designed to reduce energy consumption in the state. 
 12.10  Projects must explicitly set forth strategies for delivering 
 12.11  energy conservation improvements and may include financial 
 12.12  incentives including interest rates, prices, and terms under 
 12.13  which the improvements are offered to the customers. 
 12.14     (b) Projects must be categorized as residential, 
 12.15  commercial, or industrial to reflect the market sectors 
 12.16  targeted.  Additional classification may be authorized by the 
 12.17  department.  Projects must cover a two-year period. 
 12.18     (c) The contractor shall provide to the extent practicable 
 12.19  for a free choice, by customers participating in the projects, 
 12.20  of the device, method, material, or project constituting the 
 12.21  energy conservation improvement and for a free choice of the 
 12.22  seller or installer of the energy conservation improvement; 
 12.23  provided that the device, method, material, or project seller or 
 12.24  installer is duly licensed, certified, approved, or qualified, 
 12.25  when applicable. 
 12.26     (d) Load management projects may be funded if it results in 
 12.27  a demonstrable reduction in consumption of energy. 
 12.28     (e) Activities to reduce energy use through the design and 
 12.29  operation of buildings must be included as part of any 
 12.30  conservation effort. 
 12.31     Sec. 3.  [216E.05] [UNIVERSAL SERVICE PROGRAM.] 
 12.32     Subdivision 1.  [ESTABLISHMENT OF UNIVERSAL SERVICE 
 12.33  PROGRAM.] The department of economic security shall establish a 
 12.34  universal service program for the purposes of providing bill 
 12.35  payment and energy conservation assistance to low-income 
 12.36  customers. 
 13.1      Subd. 2.  [GOAL.] The goal of the universal service program 
 13.2   is to reduce the energy burden of at least 50 percent of 
 13.3   income-eligible customers.  To the extent feasible, the fund 
 13.4   must reduce the energy burden to no more than three percent of 
 13.5   household income. 
 13.6      Subd. 3.  [ELIGIBILITY.] Customers are eligible to 
 13.7   participate in the universal service program if household income 
 13.8   does not exceed 60 percent of the state median income. 
 13.9      Subd. 4.  [DUTIES OF ADMINISTRATOR.] (a) The administrator 
 13.10  shall design, implement, and administer a uniform statewide 
 13.11  universal service program.  The program design must include bill 
 13.12  payment and energy conservation components.  Priorities for 
 13.13  assistance must include households with the highest total energy 
 13.14  burdens, payment-troubled customers, and households with 
 13.15  residents who are elderly or have disabilities.  A household 
 13.16  whose income consists solely of means-tested public assistance 
 13.17  is categorically eligible for assistance. 
 13.18     (b) The administrator shall develop and implement a 
 13.19  comprehensive outreach plan to increase awareness of, and 
 13.20  participation in, the universal service program.  The outreach 
 13.21  plan must: 
 13.22     (1) include specific efforts to reach non-English-speaking 
 13.23  persons, communities of color, elderly citizens, and persons 
 13.24  with disabilities; 
 13.25     (2) use other state agencies with access to income-eligible 
 13.26  customers to provide information about, and applications for, 
 13.27  the program and to automatically verify income wherever possible.
 13.28     (c) The administrator shall develop and implement a 
 13.29  statewide, uniform, real-time computer system that enables the 
 13.30  administrator to track participant levels, payments, 
 13.31  consumption, and other data required for program reporting. 
 13.32     (d) The administrator shall transfer a percentage of the 
 13.33  universal service fund for energy efficiency and conservation 
 13.34  services based on the ability of those services to lower the 
 13.35  household energy burden by at least 25 percent; however, in no 
 13.36  case may the percentage transfer exceed 15 percent. 
 14.1      (e) The administrator shall limit administrative costs to 
 14.2   no more than ten percent of the fund. 
 14.3      Subd. 5.  [COORDINATION.] The administrator shall 
 14.4   coordinate the universal service program with the federal Energy 
 14.5   Assistance Program and the Weatherization Assistance Program, 
 14.6   and with any distribution utility program providing assistance 
 14.7   to low-income customers. 
 14.8      Subd. 6.  [REPORT TO THE LEGISLATURE.] The commission 
 14.9   shall, by January 31, 2003, and thereafter every two years, 
 14.10  report to the legislature concerning the operation of the fund.  
 14.11  The report must include, but is not limited to, an assessment of 
 14.12  the needs the fund is designed to meet and recommendations 
 14.13  concerning whether modifications in funding are necessary.  The 
 14.14  report must also include the following information concerning 
 14.15  the universal service program: 
 14.16     (1) the number of participants served; 
 14.17     (2) the percentage of the total eligible population served; 
 14.18     (3) the amount of money currently in the fund; 
 14.19     (4) the amount expended during the year; 
 14.20     (5) how the program was coordinated with the federal energy 
 14.21  assistance and weatherization assistance programs and any 
 14.22  distribution utility programs; 
 14.23     (6) the nature of the services provided by the program; 
 14.24     (7) administrative and all other costs not associated with 
 14.25  direct financial and conservation assistance; 
 14.26     (8) the average reduction of energy burden for 
 14.27  participating households; and 
 14.28     (9) an assessment of whether the current funding level is 
 14.29  adequate to meet the goals of the program and the needs of 
 14.30  low-income customers in the state. 
 14.31                             ARTICLE 4
 14.32                   RENEWABLES PORTFOLIO STANDARD
 14.33     Section 1.  [216E.06] [RENEWABLES PORTFOLIO STANDARD.] 
 14.34     Subdivision 1.  [ESTABLISHMENT.] A renewables portfolio 
 14.35  standard is established at a level equivalent to all of the 
 14.36  electric energy provided to end-users during 2002 that was 
 15.1   derived from renewable energy resources, as determined by the 
 15.2   department, commencing January 1, 2004.  The renewables 
 15.3   portfolio standard must rise by no less than an additional 1.5 
 15.4   percent of total state electricity consumption annually by no 
 15.5   later than January 1, 2005, and each year thereafter through 
 15.6   2010 as follows: 
 15.7      (1) by December 31, 2005, 2002 renewables level plus 1.5 
 15.8   percent; 
 15.9      (2) by December 31, 2006, 2002 renewables level plus 3.0 
 15.10  percent; 
 15.11     (3) by December 31, 2007, 2002 renewables level plus 4.5 
 15.12  percent; 
 15.13     (4) by December 31, 2008, 2002 renewables level plus 6.0 
 15.14  percent; 
 15.15     (5) by December 31, 2009, 2002 renewables level plus 7.5 
 15.16  percent; and 
 15.17     (6) by December 31, 2010, 2002 renewables level plus 9.0 
 15.18  percent. 
 15.19     Subd. 2.  [RENEWABLE ENERGY CREDITS.] (a) Renewable energy 
 15.20  credits must be certified by the commissioner.  A certification 
 15.21  fee may be charged for the sole purpose of covering reasonable 
 15.22  costs of certification.  The commission or its duly authorized 
 15.23  agents have full inspection and audit rights for the purpose of 
 15.24  verifying certification claims. 
 15.25     (b) The false representation or false certification of 
 15.26  renewable energy credits is unlawful and punishable as a 
 15.27  misdemeanor. 
 15.28     (c) The department shall, in consultation with the office 
 15.29  of the attorney general, impose sufficient penalties on retail 
 15.30  electricity suppliers, utility distribution companies, and 
 15.31  self-generators to ensure full compliance with this section.  
 15.32  Failure to produce a sufficient number of renewable energy 
 15.33  credits to comply with the renewables portfolio standard is a 
 15.34  violation and the violator is subject to a penalty equal to 
 15.35  three times the market value of a renewable energy credit for 
 15.36  each credit that is not produced. 
 16.1      (d) The department shall implement a system of cost 
 16.2   containment that is distinct from the penalty, that does not 
 16.3   undermine the market for renewable energy credits, and that 
 16.4   avoids the need to award funds on an administrative basis.  If 
 16.5   renewable energy credits are not available on the market for the 
 16.6   "cap price" of 4.75 cents or less, the department shall sell 
 16.7   "proxy" credits at the cap prices to any retail seller.  Retail 
 16.8   sellers may request any number of either type of credit.  The 
 16.9   department shall use proceeds from sales of proxy credits to 
 16.10  purchase renewable energy credits in the market, lowest prices 
 16.11  first, until the proceeds are expended. 
 16.12     (e) Upon passage of a renewables portfolio standard in 
 16.13  another state that includes the same definition of renewables 
 16.14  and begins at a level commensurate to the existing level of 
 16.15  renewables in that state, the department is authorized to 
 16.16  facilitate the trading of renewable energy credits between 
 16.17  parties located in this and that state. 
 16.18     (f) Each retail electricity supplier and utility 
 16.19  distribution company shall provide evidence, on an annual basis 
 16.20  to the department, of ownership of renewable energy credits 
 16.21  equal to the product of its total electricity sales to 
 16.22  end-users, denominated in kilowatt-hours (kWh), and the 
 16.23  renewables portfolio standard. 
 16.24     (g) All retail electricity suppliers shall, in their 
 16.25  customer bills, disclose the fraction of sales that are 
 16.26  accompanied by renewable energy credits. 
 16.27     Subd. 3.  [RULES.] The department shall devise any further 
 16.28  rules that are necessary to implement this section.  It is not 
 16.29  the intent of this section to preclude commission oversight of 
 16.30  the performance of regulated utilities in meeting the 
 16.31  requirements of this section. 
 16.32     Subd. 4.  [EVALUATION.] The department shall gather 
 16.33  available data and devise measures to gauge the success of this 
 16.34  policy.  On an annual basis no later than May 31, the department 
 16.35  shall publish a report for the previous year that includes data, 
 16.36  program results, and steps taken to improve the program results. 
 17.1      Subd. 5.  [ENFORCEMENT.] (a) A person may commence a civil 
 17.2   action in the person's own behalf against: 
 17.3      (1) a person or business who is alleged to be in violation 
 17.4   of this article, or any order issued by the department to carry 
 17.5   out these provisions; 
 17.6      (2) the department or designated entity when there is an 
 17.7   alleged failure to perform an act or duty under this section 
 17.8   that is not discretionary; or 
 17.9      (3) a person or business who falsely certifies or attempts 
 17.10  to falsely certify renewable energy credits. 
 17.11     (b) For purposes of this section, if a person or business 
 17.12  complied in good faith with a rule adopted under the authority 
 17.13  of this section, then it may not be deemed to have violated any 
 17.14  provision of this section. 
 17.15                             ARTICLE 5
 17.16                      ENVIRONMENTAL PROTECTION
 17.17     Section 1.  [216E.07] [ENVIRONMENTAL PROTECTION.] 
 17.18     The purposes of this article are to: 
 17.19     (1) protect and preserve the environment while safeguarding 
 17.20  health; 
 17.21     (2) ensure that each fossil fuel-fired electric generating 
 17.22  unit minimizes pollution to levels that are technologically 
 17.23  feasible through modernization and application of pollution 
 17.24  controls; and 
 17.25     (3) decrease significantly the threat to human health and 
 17.26  the environment posed by mercury and other hazardous chemicals 
 17.27  resulting from the combustion of fossil fuels. 
 17.28     Sec. 2.  [216E.08] [DEFINITIONS.] 
 17.29     Subdivision 1.  [SCOPE.] For purposes of this article, the 
 17.30  terms defined in this section have the meanings given them. 
 17.31     Subd. 2.  [AGENCY.] "Agency" means the pollution control 
 17.32  agency. 
 17.33     Subd. 3.  [COMMISSIONER.] "Commissioner" means the 
 17.34  commissioner of the pollution control agency. 
 17.35     Sec. 3.  [216E.09] [EMISSIONS PERMIT.] 
 17.36     Subdivision 1.  [APPLICATION.] On or before December 31, 
 18.1   2005, the owner or operator of an electric generating facility 
 18.2   shall apply to the agency for a permit to emit air contaminants. 
 18.3   On or after January 1, 2007, no person shall operate an electric 
 18.4   generating facility without a permit. 
 18.5      Subd. 2.  [NOTICE OF INTENT TO OBTAIN PERMIT; PUBLIC 
 18.6   HEARING REQUIRED.] (a) An applicant for a permit required under 
 18.7   subdivision 1 shall publish notice of intent to obtain the 
 18.8   permit. 
 18.9      (b) The agency shall provide an opportunity for a public 
 18.10  hearing and the submission of public comment and send notice of 
 18.11  a decision on an application for a permit submitted under 
 18.12  subdivision 1. 
 18.13     Subd. 3.  [REVIEW AND RENEWAL OF PERMIT.] The agency shall 
 18.14  review and renew a permit under this section in accordance with 
 18.15  Minnesota Rules. 
 18.16     Subd. 4.  [REQUIREMENTS.] A permit issued by the agency 
 18.17  under this section must require the facility to achieve 
 18.18  emissions reductions as provided under section 216E.10.  
 18.19  Notwithstanding any provision in Minnesota Rules, a facility 
 18.20  that does not obtain a permit as required by this section may 
 18.21  not operate after December 31, 2007, unless the agency finds 
 18.22  good cause for an extension. 
 18.23     Subd. 5.  [COMPLIANCE RULES.] By rule, the agency shall 
 18.24  provide methods to determine whether an electric generating 
 18.25  facility complies with the permit issued under this section.  
 18.26  The rules must provide for monitoring and reporting actual 
 18.27  emissions of sulfur dioxides, nitrogen oxides, carbon dioxide, 
 18.28  and mercury from each facility for each calendar quarter. 
 18.29     Subd. 6.  [ENFORCEMENT.] In addition to any other 
 18.30  enforcement actions available, the commissioner of the agency 
 18.31  may, after notice and hearing, revoke or temporarily suspend a 
 18.32  permit issued under subdivision 1. 
 18.33     Sec. 4.  [216E.10] [EMISSIONS LIMITS.] 
 18.34     Subdivision 1.  [RULES.] (a) Not later than December 31, 
 18.35  2002, the agency shall adopt a final rule that establishes a 
 18.36  schedule of limits on the quantity of each pollutant that all 
 19.1   covered electric generating facilities shall, in the aggregate, 
 19.2   statewide, be permitted to emit in each year beginning in the 
 19.3   calendar year 2007 as follows: 
 19.4      (1) the statewide emissions standard for calendar year 2007 
 19.5   and each year thereafter must not be greater than 25,000 tons 
 19.6   for nitrogen oxide and 45,000 tons for sulfur dioxide; and 
 19.7      (2) the statewide emission standard for calendar year 2005 
 19.8   and each year thereafter must not be greater than 425 pounds for 
 19.9   mercury and 30,000,000 tons for carbon dioxide. 
 19.10     (b) Notwithstanding any other statute, this article does 
 19.11  not limit the authority of the agency to require further 
 19.12  reductions of nitrogen oxides, sulfur dioxides, mercury, carbon 
 19.13  dioxides, or any other pollutant from generating facilities 
 19.14  subject to this chapter. 
 19.15     Subd. 2.  [MONITORING.] (a) The agency shall establish a 
 19.16  system for accurately monitoring the quantity of each pollutant 
 19.17  that an electric generating facility emits during a year. 
 19.18     (b) The owner or operator of an electric generating 
 19.19  facility shall install a continuous monitoring system for each 
 19.20  pollutant or, in the alternative, a mechanism approved by the 
 19.21  agency that provides data with precision, reliability, 
 19.22  accessibility, and timeliness that are equal to or greater than 
 19.23  those that would be achieved by a continuous 
 19.24  emissions-monitoring system. 
 19.25     Subd. 3.  [REPORTING.] Electric generating facilities shall 
 19.26  report, on a quarterly basis, the results of the monitoring 
 19.27  system established under subdivision 2.  The agency may require 
 19.28  electric generating facilities to report other relevant data. 
 19.29     Subd. 4.  [MODERNIZATION OF FACILITIES.] Within 40 years 
 19.30  after the electric generating facility's commenced operation or 
 19.31  five years after the enactment of this article, whichever is 
 19.32  later, every electric generating facility shall comply with the 
 19.33  most recent new source performance standards and maximum 
 19.34  achievable control technology standards promulgated under 
 19.35  sections 111 and 112 of the federal Clean Air Act. 
 19.36     Subd. 5.  [CONVERSION INCENTIVES.] ................... 
 20.1      Subd. 6.  [DISPOSAL OF MERCURY AND OTHER HAZARDOUS WASTES.] 
 20.2   Not later than two years after the date of enactment of this 
 20.3   article, the agency shall establish rules governing the disposal 
 20.4   of mercury and other hazardous wastes captured or recovered 
 20.5   through the use of an emission control method, or coal cleaning, 
 20.6   or another process associated with the consumption of fossil 
 20.7   fuels for the generation of electricity.  These rules must, at a 
 20.8   minimum, ensure that: 
 20.9      (1) the adverse environmental effects from mercury or other 
 20.10  hazardous waste are not transferred from one environmental 
 20.11  medium to another; and 
 20.12     (2) there is no release of mercury or other hazardous waste 
 20.13  into the environment. 
 20.14                             ARTICLE 6
 20.15                        CONSUMER PROTECTION
 20.16     Section 1.  [216E.11] [CONSUMER PROTECTION.] 
 20.17     Subdivision 1.  [PURPOSE; SCOPE.] It is hereby declared to 
 20.18  be the policy of this state that the continued provision of 
 20.19  electric and natural gas service to residential customers is 
 20.20  necessary for the preservation of the health and general welfare 
 20.21  and is in the public interest.  This article applies to the 
 20.22  provision of residential electric and natural gas service by 
 20.23  public utilities, municipalities, and electric cooperative 
 20.24  associations. 
 20.25     Subd. 2.  [RULES.] The commission, municipalities, and 
 20.26  electric service cooperative associations shall amend their 
 20.27  rules, policies, and procedures, consistent with this article, 
 20.28  governing customer service to: 
 20.29     (1) govern applications for and denials of service; 
 20.30     (2) provide adequate notice; 
 20.31     (3) permit third party notice and billing; 
 20.32     (4) require budget billing and payment agreements; and 
 20.33     (5) safeguard vulnerable customers against disconnections 
 20.34  of service and prevent loss of service during extreme weather 
 20.35  conditions. 
 20.36     Sec. 2.  [216E.12] [APPLICATION FOR NEW SERVICE; DENIAL OF 
 21.1   APPLICATION.] 
 21.2      Subdivision 1.  [APPLICATION FOR NEW SERVICE.] A utility 
 21.3   shall provide new service upon request of an applicant, provided 
 21.4   that the applicant: 
 21.5      (1) does not owe money for residential service provided by 
 21.6   the utility to a prior account in the applicant's name; or 
 21.7      (2) makes full payment of, or makes a payment agreement to 
 21.8   pay, amounts due for service provided by the utility to a prior 
 21.9   account in the applicant's name. 
 21.10     Subd. 2.  [DENIAL OF APPLICATION.] Within five business 
 21.11  days of receiving an application for new service, a utility 
 21.12  shall: 
 21.13     (1) provide prompt written notice to the applicant of a 
 21.14  decision to deny service; 
 21.15     (2) specify what the applicant must do to qualify for 
 21.16  service; and 
 21.17     (3) advise the applicant of the applicant's right to 
 21.18  investigation and review of the denial of service by the 
 21.19  commission, municipality, or electric cooperative association if 
 21.20  the applicant considers the denial to be without justification. 
 21.21     Subd. 3.  [MOVEMENT WITHIN SAME SERVICE TERRITORY.] On 
 21.22  moving to a new residence within the service territory of the 
 21.23  same utility, a residential customer is eligible to receive 
 21.24  service at the new residence.  The service must be considered a 
 21.25  continuation of service in all respects with any payment 
 21.26  agreement honored and with all rights and obligations of the 
 21.27  customer and the distribution utility unimpaired. 
 21.28     Subd. 4.  [BILLING.] Notwithstanding any other provisions 
 21.29  of this article, bills rendered periodically to customers by a 
 21.30  public utility must display in a conspicuous manner: 
 21.31     (1) the telephone number of the utility that the customer 
 21.32  may call for inquiries and complaints; 
 21.33     (2) the telephone number of the commission; and 
 21.34     (3) a statement that the customers may contact the 
 21.35  commission for help with unresolved complaints. 
 21.36     Sec. 3.  [216E.13] [THIRD PARTY NOTICE AND PAYMENT.] 
 22.1      Subdivision 1.  [THIRD PARTY NOTICE.] A utility customer 
 22.2   may designate a third party to receive copies of bills and all 
 22.3   notices relating to disconnection of service or collection of 
 22.4   amounts due sent to the customer if the third party agrees in 
 22.5   writing to receive the copies and notices. 
 22.6      Subd. 2.  [THIRD PARTY PAYMENT.] A utility customer may 
 22.7   designate a third party to be responsible to pay utility bills 
 22.8   on behalf of the customer if the third party agrees in writing 
 22.9   to pay the bills. 
 22.10     Subd. 3.  [NOTICE TO CUSTOMERS.] A utility shall provide 
 22.11  notice of the availability of third party notice and payment 
 22.12  options.  The notice must be easy to understand and provided to 
 22.13  all new customers when they apply for service and to existing 
 22.14  customers at least once annually. 
 22.15     Sec. 4.  [216E.14] [BUDGET BILLING PLANS.] 
 22.16     A utility shall offer a customer a budget billing plan for 
 22.17  payment of charges for service.  The commission may establish 
 22.18  the terms and conditions it deems necessary or proper for plans 
 22.19  required under this article. 
 22.20     Sec. 5.  [216E.15] [PAYMENT AGREEMENTS.] 
 22.21     Subdivision 1.  [ARREARS.] (a) A utility shall offer a 
 22.22  payment agreement for the payment of arrears to a customer who 
 22.23  is unable to pay due to financial circumstances.  
 22.24     (b) A utility is not obligated to offer a payment agreement 
 22.25  for the payment of arrears if the customer has the financial 
 22.26  resources to make full payment. 
 22.27     Subd. 2.  [CURRENT BILLS.] A utility may offer a payment 
 22.28  agreement to a customer who is unable to fully pay current bills 
 22.29  due to financial circumstances. 
 22.30     Subd. 3.  [TERMS.] A payment agreement may require a 
 22.31  customer to pay ten percent of the customer's monthly income or 
 22.32  may be another amount that is mutually agreeable to the customer 
 22.33  and the utility.  Payment agreements must be fair and equitable 
 22.34  considering the customer's financial circumstances.  Payment 
 22.35  agreements may be renegotiated if the customer's financial 
 22.36  circumstances change. 
 23.1      Subd. 4.  [UNDERCHARGES.] (a) A utility shall offer a 
 23.2   payment agreement to customers who have been undercharged if no 
 23.3   culpable conduct by the customer or a resident of the customer's 
 23.4   household caused the undercharge.  A customer may not be held 
 23.5   financially liable for any undercharge unless a bill for payment 
 23.6   for the undercharge has been rendered within one year after the 
 23.7   undercharge occurred. 
 23.8      (b) A utility shall offer a payment agreement for payment 
 23.9   of undercharges.  The agreement must cover a payment period 
 23.10  equal to the time over which the undercharge occurred or a 
 23.11  different payment period that is mutually agreeable to the 
 23.12  customer and the distribution utility; provided that, no 
 23.13  interest or delinquency fee may be charged under the agreement. 
 23.14     Subd. 5.  [DISPUTES.] The commission shall resolve disputes 
 23.15  involving payment agreements. 
 23.16     Sec. 6.  [216E.16] [DISCONNECTION OF SERVICE.] 
 23.17     Subdivision 1.  [NOTICE REQUIREMENTS.] A utility may not 
 23.18  disconnect service without providing notice at least 15 calendar 
 23.19  days prior to the date on which service is to be disconnected. 
 23.20     Subd. 2.  [TIME.] A utility may not disconnect service: 
 23.21     (1) prior to 8:00 a.m. or after 4:00 p.m., Monday through 
 23.22  Thursday; 
 23.23     (2) on Friday, Saturday, or Sunday; 
 23.24     (3) on a holiday; 
 23.25     (4) on the day preceding a holiday; or 
 23.26     (5) on a day when the utility or the commission's offices 
 23.27  are closed. 
 23.28     Subd. 3.  [FOR CUSTOMERS WITH PAYMENT AGREEMENTS.] (a) A 
 23.29  utility may disconnect a customer who has failed to make timely 
 23.30  payments on a payment agreement if the utility: 
 23.31     (1) provides an opportunity to bring the agreement into 
 23.32  compliance; or 
 23.33     (2) attempts to renegotiate the initial payment agreement 
 23.34  and enters into a new payment agreement. 
 23.35     (b) A utility may disconnect service, with notice as 
 23.36  required in subdivision 1, following the failure to make timely 
 24.1   payments on a second payment agreement. 
 24.2      Subd. 4.  [SPECIAL PROTECTIONS.] (a) Between April 15 and 
 24.3   October 15, a utility may not disconnect service to a residence 
 24.4   where the customer or a resident of the customer's household is 
 24.5   62 years of age or older, is five years of age or younger, or 
 24.6   has a disability unless the utility: 
 24.7      (1) makes a diligent effort to make personal contact with 
 24.8   an adult resident of the customer's household at least 72 hours 
 24.9   prior to termination of service to attempt to avert 
 24.10  disconnection; 
 24.11     (2) offers the customer the opportunity to enter into a 
 24.12  payment agreement; and 
 24.13     (3) provides a referral to, including the telephone number 
 24.14  of, the local energy assistance program provider and the county 
 24.15  social or human services department. 
 24.16     (b) A utility shall restore or continue for no less than 30 
 24.17  days and as much as 60 days service to a customer's residence 
 24.18  where a medical emergency exists if the utility receives from a 
 24.19  medical doctor written certification, or initial certification 
 24.20  by telephone and written certification within five business 
 24.21  days, that failure to restore service or the disconnection of 
 24.22  service will aggravate an existing medical emergency at a 
 24.23  customer's residence. 
 24.24     Subd. 5.  [MEDICALLY NECESSARY EQUIPMENT.] A utility shall 
 24.25  restore or continue service to a household in which a person 
 24.26  using medically necessary equipment resides.  A utility may 
 24.27  request written certification from a medical doctor that 
 24.28  restoration or continuance of utility service is necessary for 
 24.29  the preservation of life. 
 24.30     Subd. 6.  [EXTREME WEATHER PERIODS.] (a) During the period 
 24.31  between October 15 and the following April 15, a utility: 
 24.32     (1) may disconnect only those households whose incomes are 
 24.33  above 250 percent of the federal income poverty guidelines and 
 24.34  when health and safety would not be endangered; 
 24.35     (2) is responsible for demonstrating that a household is 
 24.36  eligible for disconnection; 
 25.1      (3) shall meet personally with a responsible adult member 
 25.2   of the household, prior to and again at the time of 
 25.3   disconnection, to discover any circumstances that deserve 
 25.4   special attention, such as age, infirmity, medical problems, or 
 25.5   disabilities; 
 25.6      (4) shall maintain a record of all contacts with the 
 25.7   household from the time that notice of pending disconnection is 
 25.8   first given; 
 25.9      (5) shall provide its emergency after-hours telephone 
 25.10  number to all households scheduled for disconnection; 
 25.11     (6) shall offer the customer the opportunity to enter into 
 25.12  a payment agreement or offer a noncustomer occupant the option 
 25.13  of accepting responsibility for future bills; and 
 25.14     (7) shall provide a referral to, including the telephone 
 25.15  number of, the local energy assistance program provider and the 
 25.16  county social or human services department. 
 25.17     (b) By the end of the work day following the day of 
 25.18  disconnection, the utility or the utility's designated employee 
 25.19  shall make a personal visit to the occupied dwelling to check on 
 25.20  the household's well-being and to ensure there is no danger to 
 25.21  human health or life, including the use of unsafe heating or 
 25.22  lighting devices.  If the utility or its representative observes 
 25.23  a danger to human health or life due to the disconnection, the 
 25.24  utility shall immediately restore service. 
 25.25     (c) A utility shall designate one or more management-level 
 25.26  employees to be responsible for final approval of the 
 25.27  disconnection of service and, by October 1 of each year, notify 
 25.28  the commission, in writing, of the name, title, and contact 
 25.29  number of the person or persons so designated.  The designated 
 25.30  employee shall certify on a form approved by the commission that 
 25.31  conditions for disconnection under paragraph (a) have been met 
 25.32  and shall, by telephone, report each disconnection of service to 
 25.33  an occupied dwelling during the period between October 15 and 
 25.34  the following April 15 to the consumer assistance bureau of the 
 25.35  commission by 3:00 p.m. the same day the disconnection takes 
 25.36  place. 
 26.1      (d) An electric distribution utility shall not disconnect 
 26.2   service for at least two days after a heat advisory, heat 
 26.3   warning, or heat emergency has been issued by the National 
 26.4   Weather Service in any county in the distribution utility's 
 26.5   service territory. 
 26.6      Subd. 7.  [RESPONSIBILITY FOR PAYMENT OF 
 26.7   BILLS.] Notwithstanding programs offered by distribution 
 26.8   utilities that include forgiveness of all or part of past due 
 26.9   bills, a customer is not relieved from responsibility for paying 
 26.10  bills that accrue as a result of compliance with this section. 
 26.11     Sec. 7.  [216E.17] [REPORTING.] 
 26.12     By February 1 of each year, each distribution utility shall 
 26.13  report the following information for the previous calendar year 
 26.14  to the commission: 
 26.15     (1) the total number of residential, low-income, 
 26.16  commercial, and industrial customers; 
 26.17     (2) of the amount in clause (1), the total number of 
 26.18  low-income customers receiving federal or state energy 
 26.19  assistance; 
 26.20     (3) the total dollar amount the utility received from 
 26.21  federal or state sources for energy assistance for the utility's 
 26.22  customers; 
 26.23     (4) the total dollar amount of unpaid bills or other bad 
 26.24  debt attributable to each category of customer identified in 
 26.25  clause (1); 
 26.26     (5) the total number of residential, low-income, 
 26.27  commercial, and industrial customers who had service 
 26.28  disconnected; 
 26.29     (6) of the amount in clause (5), the number of service 
 26.30  connections each month that were disconnections of heat service; 
 26.31     (7) the total dollar amount of unpaid bills or other bad 
 26.32  debt attributable to each category of customer identified in 
 26.33  clause (5); 
 26.34     (8) the total number of residential and low-income 
 26.35  customers with payment agreements and number of successfully 
 26.36  completed payment arrangements; 
 27.1      (9) the total number of residential and low-income 
 27.2   customers disconnected for failure to make timely payment on a 
 27.3   second payment agreement; and 
 27.4      (10) the total number of residential and low-income 
 27.5   customers on budget billing plans. 
 27.6      Sec. 8.  [216E.18] [COMMISSION AUTHORITY.] 
 27.7      The commission, or staff designated by the commission, has 
 27.8   the authority to order resolutions of disputes involving alleged 
 27.9   violations of this chapter or any other disputes involving the 
 27.10  businesses coming within its jurisdictions. 
 27.11                             ARTICLE 7
 27.12                         WORKER PROTECTIONS
 27.13     Section 1.  [216E.19] [WORKER PROTECTIONS; SALE OR TRANSFER 
 27.14  OF FACILITIES.] 
 27.15     An affiliate, nonutility affiliate, or other entity 
 27.16  acquiring through sale, transfer, or any other means shall: 
 27.17     (1) recognize the existing employee bargaining unit; 
 27.18     (2) honor an existing bargaining unit for the duration of 
 27.19  the agreement; 
 27.20     (3) offer employment to the nonsupervisory employees 
 27.21  employed with the energy unit or public utility immediately 
 27.22  prior to the acquisition; and 
 27.23     (4) bargain in good faith with the existing collective 
 27.24  bargaining unit when the existing bargaining agreement has 
 27.25  expired. 
 27.26                             ARTICLE 8
 27.27                SERVICE QUALITY STANDARDS GENERALLY
 27.28     Section 1.  [216E.20] [SERVICE QUALITY STANDARDS; 
 27.29  PENALTIES.] 
 27.30     Subdivision 1.  [ESTABLISHMENT.] The commission shall 
 27.31  establish service quality standards to ensure the adequate 
 27.32  provision of utility service.  The standards must include, but 
 27.33  are not limited to, the following: 
 27.34     (1) emergency repair response time; 
 27.35     (2) service outages; 
 27.36     (3) distribution system upgrades; 
 28.1      (4) safety measures; and 
 28.2      (5) customer service, including number of and timeliness of 
 28.3   response to complaints, telephone response time, response time 
 28.4   to restore service, and number of disconnections. 
 28.5      Subd. 2.  [PENALTIES.] The commission, after hearing and 
 28.6   finding a failure to comply with any of the standards 
 28.7   established, may impose a penalty appropriate to the number and 
 28.8   severity of failures and sufficient to ensure compliance and 
 28.9   adequacy of service. 
 28.10                             ARTICLE 9
 28.11               ELECTRIC SERVICE RELIABILITY STANDARDS
 28.12     Section 1.  [216E.21] [DEFINITIONS.] 
 28.13     Subdivision 1.  [SCOPE.] The terms used in this article 
 28.14  have the meanings given them in this section. 
 28.15     Subd. 2.  [AVERAGE NUMBER OF CUSTOMERS SERVED.] "Average 
 28.16  number of customers served" means the number of active, metered, 
 28.17  customer accounts available in a utility's 
 28.18  interruption-reporting database on the day that an interruption 
 28.19  occurs. 
 28.20     Subd. 3.  [CIRCUIT.] "Circuit" means a set of conductors 
 28.21  serving customer loads that are capable of being separated from 
 28.22  the serving substation automatically by a recloser, fuse, 
 28.23  sectionalizing equipment, and other devices. 
 28.24     Subd. 4.  [COMPONENT.] "Component" means a piece of 
 28.25  equipment, a line, a section of line, or a group of items that 
 28.26  is an entity for purposes of reporting, analyzing, and 
 28.27  predicting interruptions. 
 28.28     Subd. 5.  [CUSTOMER.] "Customer" means a separately metered 
 28.29  electrical service point for which a separate bill is rendered, 
 28.30  i.e., each meter represents a customer. 
 28.31     Subd. 6.  [CUSTOMER INTERRUPTION.] "Customer interruption" 
 28.32  means the loss of service due to a forced outage for more than 
 28.33  five minutes, for one or more customers, which is the result of 
 28.34  one or more component failures. 
 28.35     Subd. 7.  [CUSTOMERS' INTERRUPTIONS CAUSED BY POWER 
 28.36  RESTORATION PROCESS.] "Customers' interruptions caused by power 
 29.1   restoration process" means when customers lose power as a result 
 29.2   of the process of restoring power.  The duration of these 
 29.3   outages is included in the customer-minutes of interruption.  
 29.4   Only the customers affected by the power restoration outages 
 29.5   that were not affected by the original outage are added to the 
 29.6   number of customer interruptions.  
 29.7      Subd. 8.  [CUSTOMER-MINUTES OF 
 29.8   INTERRUPTION.] "Customer-minutes of interruption" means the 
 29.9   number of minutes of forced outage duration multiplied by the 
 29.10  number of customers affected. 
 29.11     Subd. 9.  [ELECTRIC DISTRIBUTION LINE.] "Electric 
 29.12  distribution line" means circuits operating at less than 40,000 
 29.13  volts. 
 29.14     Subd. 10.  [FORCED OUTAGE.] "Forced outage" means an outage 
 29.15  that cannot be deferred. 
 29.16     Subd. 11.  [MAJOR CATASTROPHIC EVENTS.] "Major catastrophic 
 29.17  events" means events that are beyond the utility's control that 
 29.18  result in widespread system damages causing customer 
 29.19  interruptions that affect at least ten percent of the customers 
 29.20  in the system or in an operating area or that result in 
 29.21  customers being without electric service for durations of at 
 29.22  least 24 hours. 
 29.23     Subd. 12.  [MAJOR STORM.] "Major storm" means a period of 
 29.24  severe adverse weather resulting in widespread system damage 
 29.25  causing customer interruptions that affect at least ten percent 
 29.26  of the customers on the system or in an operating area or that 
 29.27  result in customers being without electric service for durations 
 29.28  of at least 24 hours. 
 29.29     Subd. 13.  [MOMENTARY INTERRUPTION.] "Momentary 
 29.30  interruption" means an interruption of electric service with a 
 29.31  duration shorter than the time necessary to be classified as a 
 29.32  customer interruption. 
 29.33     Subd. 14.  [OPERATING AREA.] "Operating area" means a 
 29.34  geographical subdivision of each electric utility's service 
 29.35  territory that functions under the direction of a company office 
 29.36  and may be used for reporting interruptions under this article.  
 30.1   These areas may also be referred to as regions, divisions, or 
 30.2   districts. 
 30.3      Subd. 15.  [OUTAGE.] "Outage" means the failure of a power 
 30.4   system component that results in one or more customer 
 30.5   interruptions. 
 30.6      Subd. 16.  [OUTAGE DURATION.] "Outage duration" means the 
 30.7   one minute or greater period from the initiation of an 
 30.8   interruption to a customer until service has been restored to 
 30.9   that customer. 
 30.10     Subd. 17.  [PARTIAL CIRCUIT OUTAGE CUSTOMER 
 30.11  COUNT.] "Partial circuit outage customer count" means when only 
 30.12  part of a circuit experiences an outage, the number of customers 
 30.13  affected is estimated, unless an actual count is available.  
 30.14  When power is partially restored, the number of customers 
 30.15  restored is also estimated.  Most utilities use estimates based 
 30.16  on the portion of the circuit restored. 
 30.17     Subd. 18.  [PLANNED OUTAGES.] "Planned outages" means those 
 30.18  outages scheduled by the utility.  When customer service 
 30.19  interruptions are necessary, the utility shall notify affected 
 30.20  customers in advance.  These interruptions are sometimes 
 30.21  necessary to connect new customers or perform maintenance 
 30.22  activities safely.  They must not be included in the calculation 
 30.23  of reliability indexes. 
 30.24     Subd. 19.  [RELIABILITY.] "Reliability" means the degree to 
 30.25  which electric service is supplied without interruption. 
 30.26     Subd. 20.  [RELIABILITY INDEXES.] "Reliability indexes" 
 30.27  include the following performance indices for measuring 
 30.28  frequency and duration of service interruptions: 
 30.29     (a) The system average interruption frequency index is the 
 30.30  average number of interruptions per customer per year.  It is 
 30.31  determined by dividing the total annual number of customer 
 30.32  interruptions by the average number of customers served during 
 30.33  the year. 
 30.34     (b) The system average interruption duration index is the 
 30.35  average customer-minutes of interruption per customer.  It is 
 30.36  determined by dividing the annual sum of customer-minutes of 
 31.1   interruption by the average number of customers served during 
 31.2   the year. 
 31.3      (c) The customer average interruption duration index is the 
 31.4   average customer-minutes of interruption per customer 
 31.5   interruption.  It approximates the average length of time 
 31.6   required to complete service restoration.  It is determined by 
 31.7   dividing the annual sum of all customer-minutes of interruption 
 31.8   durations by the annual number of customer interruptions. 
 31.9      Sec. 2.  [216E.22] [RECORDING STANDARDS.] 
 31.10     Subdivision 1.  [ANNUAL RECORD.] Each electric utility with 
 31.11  1,000 retail customers or more shall keep a record of the 
 31.12  necessary interruption data and calculate the system average 
 31.13  interruption frequency index, system average interruption 
 31.14  duration index, and customer average interruption duration index 
 31.15  of its system, and of each operating area, if applicable, at the 
 31.16  end of each calendar year for the previous 12-month period. 
 31.17     Subd. 2.  [CALCULATION IN ORDER BY OPERATING AREA.] Each 
 31.18  utility also shall, at the end of each calendar year, calculate 
 31.19  the system average interruption frequency index, system average 
 31.20  interruption duration index, and customer average interruption 
 31.21  duration index for each circuit in each operating area.  Each 
 31.22  circuit in each operating area must then be listed in order 
 31.23  separately according to its system average interruption 
 31.24  frequency index, its system average interruption duration index, 
 31.25  and its customer average interruption duration index, beginning 
 31.26  with the highest values for each index. 
 31.27     Sec. 3.  [216E.23] [ANNUAL REPORT.] 
 31.28     Subdivision 1.  [SUMMARY REPORT GENERALLY.] Beginning on 
 31.29  July 1, 2002, and by July 1 of every year thereafter, each 
 31.30  electric utility with 1,000 retail customers or more shall file 
 31.31  with the commission a report summarizing various measures of 
 31.32  reliability.  The form of the report is subject to review and 
 31.33  approval by the commission staff.  Names and numbers used to 
 31.34  identify operating areas or individual circuits may conform to 
 31.35  the utility's practice, but should allow ready identification of 
 31.36  the geographic location or the general area served.  Electronic 
 32.1   recording and reporting of the required data and information is 
 32.2   encouraged.  
 32.3      Subd. 2.  [INFORMATION REQUIRED.] (a) The report shall 
 32.4   include at least the information described in paragraphs (b) to 
 32.5   (h). 
 32.6      (b) The report must provide an overall assessment of the 
 32.7   reliability of performance including the aggregate system 
 32.8   average interruption frequency index, system average 
 32.9   interruption duration index, and customer average interruption 
 32.10  duration index by system and each operating area, as applicable. 
 32.11     (c) The report must include a list of the worst performing 
 32.12  circuits based on system average interruption frequency index, 
 32.13  system average interruption duration index, and customer average 
 32.14  interruption duration index for the calendar year.  This portion 
 32.15  of the report must describe the actions that the utility has 
 32.16  taken or will take to remedy the conditions responsible for each 
 32.17  listed circuit's unacceptable performance.  The actions taken or 
 32.18  planned should be briefly described.  Target dates for 
 32.19  corrective actions must be included in the report.  When the 
 32.20  utility determines that actions on its part are unwarranted, its 
 32.21  report shall provide adequate justification for that conclusion. 
 32.22     (d) Utilities that use or prefer alternative criteria for 
 32.23  measuring individual circuit performance to those described in 
 32.24  paragraphs (b) and (c) and that are required by this section to 
 32.25  submit an annual report of reliability data, shall submit their 
 32.26  alternative listing of circuits along with the criteria used to 
 32.27  rank circuit performance. 
 32.28     (e) Information must be included with respect to any report 
 32.29  on the accomplishment of the improvements proposed in prior 
 32.30  reports for which completion has not been previously reported. 
 32.31     (f) The report must describe any new reliability or power 
 32.32  quality programs and changes that are made to existing programs. 
 32.33     (g) It must include a status report of any long-range 
 32.34  electric distribution plans. 
 32.35     (h) In addition to the information included in paragraph 
 32.36  (b), each utility shall report the following additional service 
 33.1   quality information: 
 33.2      (1) route miles of electric distribution line reconstructed 
 33.3   during the year, with separate totals for single- and 
 33.4   three-phase circuits provided; 
 33.5      (2) total route miles of electric distribution line in 
 33.6   service at year's end, segregated by voltage level; 
 33.7      (3) monthly average speed of answer for telephone calls 
 33.8   received regarding emergencies, outages, and customer billing 
 33.9   problems; 
 33.10     (4) the average number of calendar days a utility takes to 
 33.11  install and energize service to a customer site once it is ready 
 33.12  to receive service, with a separate average calculated for each 
 33.13  month, including all extensions energized during the calendar 
 33.14  month; 
 33.15     (5) the total number of written and telephone customer 
 33.16  complaints received in the areas of safety, customer billing, 
 33.17  outages, power quality, customer property damage, and other 
 33.18  areas, by month filed; 
 33.19     (6) total annual tree-trimming budget and actual expenses; 
 33.20  and 
 33.21     (7) total annual projected and actual miles of tree-trimmed 
 33.22  distribution line. 
 33.23     Sec. 4.  [216E.24] [INITIAL HISTORICAL RELIABILITY 
 33.24  PERFORMANCE REPORT.] 
 33.25     (a) Each electric utility with 1,000 retail customers or 
 33.26  more that has historically used measures of system, operating 
 33.27  area, and circuit reliability performance shall initially submit 
 33.28  annual system average interruption frequency index, system 
 33.29  average interruption duration index, and customer average 
 33.30  interruption duration index data for the previous three years.  
 33.31  Those utilities that have this data for some time period less 
 33.32  than three years shall submit data for those years it is 
 33.33  available. 
 33.34     (b) Those utilities whose historical reliability 
 33.35  performance data is similar or related to those measures defined 
 33.36  in paragraph (a), but differs due to how the parameters are 
 34.1   defined or calculated, should submit the data it has and explain 
 34.2   any material differences from the prescribed indices.  After the 
 34.3   effective date of this section, utilities shall modify their 
 34.4   reliability performance measures to conform to those specified 
 34.5   in this article for purposes of consistent reporting of 
 34.6   comparable data in the future. 
 34.7      Sec. 5.  [216E.25] [INTERRUPTIONS OF SERVICE; RECORDS; 
 34.8   NOTICE.] 
 34.9      Subdivision 1.  [RECORDS.] (a) Each utility shall keep 
 34.10  records of all interruptions to service affecting the entire 
 34.11  distribution system of any single community or an important 
 34.12  division of a community and include in the record the location, 
 34.13  date, time, and duration of interruptions, the approximate 
 34.14  number of customers affected, the circuit or circuits involved, 
 34.15  and, when known, the cause of each interruption. 
 34.16     (b) When complete distribution systems or portions of 
 34.17  communities have service furnished from unattended stations, 
 34.18  these records must be kept to the extent practicable.  The 
 34.19  record of unattended stations shall show interruptions that 
 34.20  require attention to restore service, with the estimated time of 
 34.21  interruption.  Breaker or fuse operations affecting service 
 34.22  should also be indicated even though duration of interruption 
 34.23  may not be known. 
 34.24     Subd. 2.  [NOTICE OF INTERRUPTIONS OF BULK POWER SUPPLY 
 34.25  FACILITIES.] (a) Each utility shall notify the commission of any 
 34.26  event described in paragraphs (b) to (f) involving any 
 34.27  generating unit or electric facilities operating at a nominal 
 34.28  voltage of 69 kilovolts or higher. 
 34.29     (b) Notice must be given for any interruption or loss of 
 34.30  service to customers for 15 minutes or more to aggregate firm 
 34.31  loads in excess of 200,000 kilowatts.  This notification must be 
 34.32  made by telephone as soon as practicable without unduly 
 34.33  interfering with service restoration and, in any event, within 
 34.34  one hour after the beginning of the interruption.  A confirming 
 34.35  written report must be submitted within two weeks. 
 34.36     (c) Any interruption or loss of service to customers for 15 
 35.1   minutes or more to aggregate firm loads exceeding the lesser of 
 35.2   100,000 kilowatts or one-half of the current annual system peak 
 35.3   load and not required to be reported under paragraph (b) must be 
 35.4   reported to the commission.  This notification must be made by 
 35.5   telephone no later than the beginning of the commission's next 
 35.6   regular work day after the interruption occurred.  A confirming 
 35.7   written report must be submitted within two weeks. 
 35.8      (d) A utility shall notify the commission of any decision 
 35.9   to issue a public request for reduction in use of electricity.  
 35.10  Notification of this decision must be made by telephone at the 
 35.11  time of issuing the request.  A confirming written report must 
 35.12  be submitted within two weeks. 
 35.13     (e) An action to reduce firm customer loads by reduction of 
 35.14  voltage for reasons of maintaining adequacy of bulk electric 
 35.15  power supply must be reported to the commission.  Notification 
 35.16  of this action must be made by telephone at the time of taking 
 35.17  the action.  A confirming written report must be submitted 
 35.18  within two weeks. 
 35.19     (f) The utility shall notify the commission of any action 
 35.20  to reduce firm customer loads by manual switching, operation of 
 35.21  automatic load-shedding devices, or any other means for reasons 
 35.22  of maintaining adequacy of bulk electric power supply.  
 35.23  Notification of this action must be made by telephone at the 
 35.24  time of taking the action. 
 35.25     Subd. 2.  [NOTICE OF OTHER INTERRUPTIONS OF POWER.] (a) 
 35.26  Each utility shall notify the commission of service 
 35.27  interruptions not involving bulk power supply facilities in 
 35.28  accordance with paragraph (b). 
 35.29     (b) Interruptions of 60 minutes or more to an entire 
 35.30  distribution substation bus or entire feeder serving either 500 
 35.31  or more customers or entire cities or villages having 200 or 
 35.32  more customers must be reported within two weeks by written 
 35.33  report. 
 35.34     Subd. 3.  [INFORMATION REQUIRED.] The written reports 
 35.35  required in subdivisions 1 and 2 must include the date, time, 
 35.36  duration, general location, approximate number of customers 
 36.1   affected, identification of circuit or circuits involved, and, 
 36.2   when known, the cause of the interruption.  When extensive 
 36.3   interruptions occur, as from a storm, a narrative report 
 36.4   including the extent of the interruptions and system damage, 
 36.5   estimated number of customers affected, and a list of entire 
 36.6   communities interrupted may be submitted in lieu of reports of 
 36.7   individual interruptions. 
 36.8      Sec. 6.  [216E.26] [CUSTOMERS' COMPLAINTS.] 
 36.9      (a) Each electric utility shall investigate and keep a 
 36.10  record of complaints received by it from its customers in regard 
 36.11  to safety, service, or rates and the operation of its system, 
 36.12  with appropriate response times designated for critical safety 
 36.13  and monetary loss situations.  The record must show the name and 
 36.14  address of the complainant, the date and nature of the 
 36.15  complaint, the priority assigned to the assistance, and its 
 36.16  disposition and the time and date of its disposition. 
 36.17     (b) Each electric utility also shall document all contacts 
 36.18  and action relative to deferred payment agreements and disputes. 
 36.19                             ARTICLE 10 
 36.20                       DISTRIBUTED RESOURCES 
 36.21     Section 1.  Minnesota Statutes 2000, section 216B.164, 
 36.22  subdivision 3, is amended to read: 
 36.23     Subd. 3.  [PURCHASES; SMALL FACILITIES.] (a) For a 
 36.24  qualifying facility having two megawatts or less than 
 36.25  40-kilowatt capacity, the customer shall must be billed for the 
 36.26  net energy supplied by the utility according to the applicable 
 36.27  rate schedule for sales to that class of customer.  In the case 
 36.28  of net input into the utility system by a qualifying facility 
 36.29  having less than 40-kilowatt capacity, compensation to the 
 36.30  customer shall must be at a per kilowatt-hour rate determined 
 36.31  under paragraph (b) or (c) of this subdivision.  
 36.32     (b) In setting rates, the commission shall consider the 
 36.33  fixed distribution costs to the utility not otherwise accounted 
 36.34  for in the basic monthly charge and shall ensure that the costs 
 36.35  charged to the qualifying facility are not discriminatory in 
 36.36  relation to the costs charged to other customers of the utility. 
 37.1   The commission shall set the rates for net input into the 
 37.2   utility system based on avoided costs as defined in the Code of 
 37.3   Federal Regulations, title 18, section 292.101, 
 37.4   paragraph (b)(6), the factors listed in Code of Federal 
 37.5   Regulations, title 18, section 292.304, and all other relevant 
 37.6   factors.  
 37.7      (c) Notwithstanding any provision in this chapter to the 
 37.8   contrary, a qualifying facility having less than 40-kilowatt 
 37.9   capacity may elect that the compensation for net input by the 
 37.10  qualifying facility into the utility system shall must be at the 
 37.11  average retail utility energy rate.  "Average retail utility 
 37.12  energy rate" is defined as the average of the retail energy 
 37.13  rates, exclusive of special rates based on income, age, or 
 37.14  energy conservation, according to the applicable rate schedule 
 37.15  of the utility for sales to that class of customer.  For a 
 37.16  qualifying facility of 40-kilowatt capacity or greater, up to 
 37.17  two megawatts of capacity, the compensation for net input by the 
 37.18  qualifying facility into the utility system must be based on the 
 37.19  market price for energy at the time the facility was putting 
 37.20  energy into the utility system.  
 37.21     (d) If the qualifying facility is interconnected with a 
 37.22  nongenerating utility which that has a sole source contract with 
 37.23  a municipal power agency or a generation and transmission 
 37.24  utility, the nongenerating utility may elect to treat its 
 37.25  purchase of any net input under this subdivision as being made 
 37.26  on behalf of its supplier and shall must be reimbursed by its 
 37.27  supplier for any additional costs incurred in making the 
 37.28  purchase.  Qualifying facilities having less than 40-kilowatt 
 37.29  capacity may, at the customer's option, elect to be governed by 
 37.30  the provisions of subdivision 4.  
 37.31     Sec. 2.  Minnesota Statutes 2000, section 216B.164, 
 37.32  subdivision 6, is amended to read: 
 37.33     Subd. 6.  [RULES AND UNIFORM CONTRACT.] (a) The commission 
 37.34  shall promulgate rules to implement the provisions of this 
 37.35  section.  The commission shall also establish a uniform 
 37.36  statewide form of contract for use between utilities and a 
 38.1   qualifying facility having a capacity of two megawatts or less 
 38.2   than 40-kilowatt capacity.  
 38.3      (b) The commission shall require the qualifying facility to 
 38.4   provide the utility with reasonable access to the premises and 
 38.5   equipment of the qualifying facility if the particular 
 38.6   configuration of the qualifying facility precludes disconnection 
 38.7   or testing of the qualifying facility from the utility side of 
 38.8   the interconnection with the utility remaining responsible for 
 38.9   its personnel.  
 38.10     (c) The uniform statewide form of contract shall must be 
 38.11  applied to all new and existing interconnections established 
 38.12  between a utility and a qualifying facility having less than 
 38.13  40-kilowatt capacity, except that existing contracts may remain 
 38.14  in force until written notice of election that the uniform 
 38.15  statewide contract form applies is given by either party to the 
 38.16  other, with the notice being of the shortest time period 
 38.17  permitted under the existing contract for termination of the 
 38.18  existing contract by either party, but not less than ten nor 
 38.19  longer than 30 days.  
 38.20     Sec. 3.  [216E.27] [APPLICATION.] 
 38.21     The term "electric utility" applies to all electric 
 38.22  utilities that own and operate equipment in the state for 
 38.23  furnishing electric service at retail. 
 38.24     Sec. 4.  [PURPOSE.] 
 38.25     The purpose of this article is to state the terms and 
 38.26  conditions that govern the interconnection and parallel 
 38.27  operation of on-site distributed generation to provide cost 
 38.28  savings and reliability benefits to customers, to establish 
 38.29  technical requirements that will promote the safe and reliable 
 38.30  parallel operation of on-site distributed generation resources, 
 38.31  to enhance both the reliability of electric service and economic 
 38.32  efficiency in the production and consumption of electricity, and 
 38.33  to promote the use of distributed resources in order to provide 
 38.34  electric system benefits during periods of capacity constraints. 
 38.35     Sec. 5.  [216E.28] [DEFINITIONS.] 
 38.36     Subdivision 1.  [SCOPE.] The terms used in this article 
 39.1   have the meanings given in this section. 
 39.2      Subd. 2.  [APPLICATION FOR INTERCONNECTION AND PARALLEL 
 39.3   OPERATION WITH THE UTILITY SYSTEM OR APPLICATION.] "Application 
 39.4   for interconnection and parallel operation with the utility 
 39.5   system or application" means a standard form of application 
 39.6   developed by the commissioner and approved by the commission. 
 39.7      Subd. 3.  [COMPANY.] "Company" means an electric utility 
 39.8   operating a distribution system. 
 39.9      Subd. 4.  [CUSTOMER.] "Customer" means any individual 
 39.10  person or entity interconnected to the company's utility system 
 39.11  for the purpose of receiving or exporting electric power from or 
 39.12  to the company's utility system. 
 39.13     Subd. 5.  [FACILITY.] "Facility" means an electrical 
 39.14  generating installation consisting of one or more on-site 
 39.15  distributed generation units.  The total capacity of a 
 39.16  facility's individual on-site distributed generation units may 
 39.17  exceed ten megawatts; however, no more than ten megawatts of a 
 39.18  facility's capacity may be interconnected at any point in time 
 39.19  at the point of common coupling under this section. 
 39.20     Subd. 6.  [INTERCONNECTION.] "Interconnection" means the 
 39.21  physical connection of distributed generation to the utility 
 39.22  system in accordance with the requirements of this section so 
 39.23  that parallel operation can occur. 
 39.24     Subd. 7.  [INTERCONNECTION AGREEMENT.] "Interconnection 
 39.25  agreement" means the standard form of agreement developed by the 
 39.26  commission and approved by the commission.  The interconnection 
 39.27  agreement sets forth the contractual conditions under which a 
 39.28  company and a customer agree that one or more facilities may be 
 39.29  interconnected with the company's utility system. 
 39.30     Subd. 8.  [INVERTER-BASED PROTECTIVE 
 39.31  FUNCTION.] "Inverter-based protective function" means a function 
 39.32  of an inverter system, carried out using hardware and software, 
 39.33  that is designed to prevent unsafe operating conditions from 
 39.34  occurring before, during, and after the interconnection of an 
 39.35  inverter-based static power converter unit with a utility 
 39.36  system.  For purposes of this definition, unsafe operating 
 40.1   conditions are conditions that, if left uncorrected, would 
 40.2   result in harm to personnel, damage to equipment, unacceptable 
 40.3   system instability, or operation outside legally established 
 40.4   parameters affecting the quality of service to other customers 
 40.5   connected to the utility system. 
 40.6      Subd. 9.  [NETWORK SERVICE.] "Network service" means two or 
 40.7   more utility primary distribution feeder sources electrically 
 40.8   tied together on the secondary, or low voltage, side to form one 
 40.9   power source for one or more customers.  The service is designed 
 40.10  to maintain service to the customers even after the loss of one 
 40.11  of these primary distribution feeder sources. 
 40.12     Subd. 10.  [ON-SITE DISTRIBUTED GENERATION OR DISTRIBUTED 
 40.13  GENERATION.] "On-site distributed generation" or "distributed 
 40.14  generation" means an electrical generating facility located at a 
 40.15  customer's point of delivery or point of common coupling of ten 
 40.16  megawatts or less and connected at a voltage less than or equal 
 40.17  to 60 kilovolts that may be connected in parallel operation to 
 40.18  the utility system. 
 40.19     Subd. 11.  [PARALLEL OPERATION.] "Parallel operation" means 
 40.20  the operation of on-site distributed generation by a customer 
 40.21  while the customer is connected to the company's utility system. 
 40.22     Subd. 12.  [POINT OF COMMON COUPLING.] "Point of common 
 40.23  coupling" means the point where the electrical conductors of the 
 40.24  company utility system are connected to the customer's 
 40.25  conductors and where any transfer of electric power between the 
 40.26  customer and the utility system takes place, such as switchgear 
 40.27  near the meter. 
 40.28     Subd. 13.  [PRECERTIFIED EQUIPMENT.] "Precertified 
 40.29  equipment" means a specific generating and protective equipment 
 40.30  system or systems that have been certified as meeting the 
 40.31  applicable parts of this section relating to safety and 
 40.32  reliability by an entity approved by the commission. 
 40.33     Subd. 14.  [PRE-INTERCONNECTION 
 40.34  STUDY.] "Pre-interconnection study" means a study that may be 
 40.35  undertaken by a company in response to its receipt of a 
 40.36  completed application for interconnection and parallel operation 
 41.1   with the utility system.  Pre-interconnection studies may 
 41.2   include, but are not limited to, service studies, coordination 
 41.3   studies, and utility system impact studies. 
 41.4      Subd. 15.  [STABILIZED.] "Stabilized" means that, following 
 41.5   a disturbance, a company utility system has returned to the 
 41.6   normal range of voltage and frequency for a duration of two 
 41.7   minutes or a shorter time as mutually agreed to by the company 
 41.8   and customer. 
 41.9      Subd. 16.  [TARIFF FOR INTERCONNECTION AND PARALLEL 
 41.10  OPERATION OF DISTRIBUTED GENERATION.] "Tariff for 
 41.11  interconnection and parallel operation of distributed 
 41.12  generation" means the commission-developed and 
 41.13  commission-approved tariff for interconnection and parallel 
 41.14  operation of distributed generation including the application 
 41.15  for interconnection and parallel operation of distributed 
 41.16  generation and pre-interconnection study fee schedule. 
 41.17     Subd. 17.  [UNIT.] "Unit" means a power generator. 
 41.18     Subd. 18.  [UTILITY SYSTEM.] "Utility system" means a 
 41.19  company's distribution system below 60 kilovolts to which the 
 41.20  generation equipment is interconnected. 
 41.21     Sec. 6.  [216E.29] [OBLIGATION TO SERVE.] 
 41.22     Subdivision 1.  [REQUIRED TARIFF FILINGS.] No later than 
 41.23  270 days after the effective date of this section each electric 
 41.24  utility shall file a tariff or tariffs for interconnection and 
 41.25  parallel operation of distributed generation in conformance with 
 41.26  the provisions of this section.  The utility may file a new 
 41.27  tariff or a modification of an existing tariff.  The tariffs 
 41.28  must ensure that back-up, supplemental, and maintenance power is 
 41.29  available to all customers and customer classes that desire such 
 41.30  service.  Any modifications of existing tariffs or offerings of 
 41.31  new tariffs relating to this subdivision must be consistent with 
 41.32  the commission-approved form.  
 41.33     Subd. 2.  [OTHER REQUIRED FILINGS.] Concurrent with the 
 41.34  tariff filing in this section, each utility shall submit: 
 41.35     (1) a schedule detailing the charges of interconnection 
 41.36  studies and all supporting cost data for the charges; 
 42.1      (2) a standard application for interconnection and parallel 
 42.2   operation of distributed generation; and 
 42.3      (3) the interconnection agreement approved by the 
 42.4   commission. 
 42.5      Sec. 7.  [216E.30] [DISCONNECTION AND RECONNECTION.] 
 42.6      A utility may disconnect a distributed generation unit from 
 42.7   the utility system under the following conditions: 
 42.8      (1) upon expiration or termination of the interconnection 
 42.9   agreement with a customer, in accordance with the terms of the 
 42.10  agreement; 
 42.11     (2) if the facility is not in compliance with the technical 
 42.12  requirements specified by the commissioner; 
 42.13     (3) when continued interconnection will endanger persons or 
 42.14  property; and 
 42.15     (4) with seven business days prior written notice of a 
 42.16  service interruption for routine maintenance, repairs, and 
 42.17  utility system modifications. 
 42.18     Sec. 8.  [216E.31] [INCREMENTAL DEMAND CHARGES.] 
 42.19     During the term of an interconnection agreement, a utility 
 42.20  may require that a customer disconnect its distributed 
 42.21  generation unit or take it off-line as a result of utility 
 42.22  system conditions.  Incremental demand charges arising from 
 42.23  disconnecting the distributed generator as directed by the 
 42.24  utility during such periods must not be assessed by the utility 
 42.25  to the customer. 
 42.26     Sec. 9.  [216E.32] [PRE-INTERCONNECTION STUDIES FOR 
 42.27  NON-NETWORK INTERCONNECTION OF DISTRIBUTED GENERATION.] 
 42.28     Subdivision 1.  [TYPES OF STUDIES.] A utility may conduct a 
 42.29  service study, coordination study, or utility system impact 
 42.30  study prior to interconnection of a distributed generation 
 42.31  facility.  When these studies are deemed necessary, the scope of 
 42.32  the studies must be based on the characteristics of the 
 42.33  particular distributed generation facility to be interconnected 
 42.34  and the utility's system at the specific proposed location.  By 
 42.35  agreement between the utility and its customer, studies related 
 42.36  to interconnection of distributed generation on the customer's 
 43.1   premises may be conducted by a qualified third party. 
 43.2      Subd. 2.  [CUSTOMER FEE PROHIBITED.] A utility may not 
 43.3   charge a customer a fee to conduct a pre-interconnection study 
 43.4   for precertified distributed generation units up to 500 
 43.5   kilowatts (kW) that export not more than 15 percent of the total 
 43.6   load on a single radial feeder and contribute not more than 25 
 43.7   percent of the maximum potential short circuit current on a 
 43.8   single radial feeder. 
 43.9      Subd. 3.  [CUSTOMER FEE ALLOWED.] (a) Prior to the 
 43.10  interconnection of a distributed generation facility not 
 43.11  described in subdivision 2, a utility may charge a customer a 
 43.12  fee to offset its costs incurred in the conduct of a 
 43.13  pre-interconnection study.  In those instances where a utility 
 43.14  conducts an interconnection study, the requirements of 
 43.15  paragraphs (b) to (e) apply. 
 43.16     (b) The conduct of such pre-interconnection study may not 
 43.17  take more than four weeks. 
 43.18     (c) A utility shall prepare written reports of the study 
 43.19  findings and make them available to the customer. 
 43.20     (d) The study must consider both the costs incurred and the 
 43.21  benefits realized as a result of the interconnection of 
 43.22  distributed generation to the company's utility system. 
 43.23     (e) The customer must receive an estimate of the study cost 
 43.24  before the utility initiates the study. 
 43.25     Sec. 10.  [216E.33] [PRE-INTERCONNECTION STUDIES FOR 
 43.26  NETWORK INTERCONNECTION OF DISTRIBUTED GENERATION.] 
 43.27     Subdivision 1.  [NOTICE AND FEE.] Prior to charging a 
 43.28  pre-interconnection study fee for a network interconnection of 
 43.29  distributed generation, a utility shall first advise the 
 43.30  customer of the potential problems associated with 
 43.31  interconnection of distributed generation with its network 
 43.32  system.  For potential interconnections to network systems there 
 43.33  must be no pre-interconnection study fee assessed for a facility 
 43.34  with inverter systems under 20 kilowatts (kW).  For all other 
 43.35  facilities the utility may charge the customer a fee to offset 
 43.36  its costs incurred in the conduct of the pre-interconnection 
 44.1   study.  
 44.2      Subd. 2.  [STUDY REQUIREMENTS.] (a) When a utility conducts 
 44.3   an interconnection study, the requirements of paragraphs (b) to 
 44.4   (e) apply. 
 44.5      (b) The conduct of a pre-interconnection study may not take 
 44.6   more than four weeks. 
 44.7      (c) A utility shall prepare written reports of the study 
 44.8   findings and make them available to the customer. 
 44.9      (d) The study must consider both the costs incurred and the 
 44.10  benefits realized as a result of the interconnection of 
 44.11  distributed generation to the utility's system. 
 44.12     (e) The customer must receive an estimate of the study cost 
 44.13  before the utility initiates the study. 
 44.14     Sec. 11.  [216E.34] [EQUIPMENT PRECERTIFICATION.] 
 44.15     (a) The commission may approve one or more entities that 
 44.16  shall precertify equipment as defined pursuant to this section. 
 44.17     (b) Testing organizations or facilities capable of 
 44.18  analyzing the function, control, and protective systems of 
 44.19  distributed generation units may request to be certified as 
 44.20  testing organizations. 
 44.21     (c) Distributed generation units that are certified to be 
 44.22  in compliance by an approved testing facility or organization as 
 44.23  described in this section must be installed on a company utility 
 44.24  system in accordance with an approved interconnection control 
 44.25  and protection scheme without further review of their design by 
 44.26  the utility. 
 44.27     Sec. 12.  [216E.35] [TIME FOR PROCESSING APPLICATIONS FOR 
 44.28  INTERCONNECTION.] 
 44.29     (a) The interconnection of distributed generation to the 
 44.30  utility system must take place as set forth in paragraphs (b) to 
 44.31  (f). 
 44.32     (b) For a facility with precertified equipment, 
 44.33  interconnection must take place within four weeks of the 
 44.34  utility's receipt of a completed interconnection application. 
 44.35     (c) For other facilities, interconnection must take place 
 44.36  within six weeks of the utility's receipt of a completed 
 45.1   application. 
 45.2      (d) If interconnection of a particular facility will 
 45.3   require substantial capital upgrades to the utility system, the 
 45.4   company shall provide the customer an estimate of the schedule 
 45.5   and the customer's cost for the upgrade.  If the customer 
 45.6   desires to proceed with the upgrade, the customer and the 
 45.7   company shall enter into a contract for the completion of the 
 45.8   upgrade.  The interconnection must take place no later than two 
 45.9   weeks following the completion of the upgrade.  The utility 
 45.10  shall employ best reasonable efforts to complete the system 
 45.11  upgrade in the shortest time reasonably practical. 
 45.12     (e) A utility shall use best reasonable efforts to 
 45.13  interconnect facilities within the time frames described in this 
 45.14  section.  If in a particular instance a utility determines that 
 45.15  it cannot interconnect a facility within the time frames stated 
 45.16  in this section, it must notify the applicant in writing of that 
 45.17  fact.  The notification must identify any reasons 
 45.18  interconnection could not be performed in accordance with the 
 45.19  schedule and provide an estimated date for interconnection. 
 45.20     (f) Applications for interconnection and parallel operation 
 45.21  of distributed generation must be processed by the utility in a 
 45.22  nondiscriminatory manner and in the order that they are 
 45.23  received.  It is recognized that certain applications may 
 45.24  require minor modifications while they are being reviewed by the 
 45.25  utility.  These minor modifications to a pending application 
 45.26  must not require that it be considered incomplete and treated as 
 45.27  a new or separate application. 
 45.28     Sec. 13.  [216E.36] [REPORTING REQUIREMENTS.] 
 45.29     (a) Each electric utility shall maintain records concerning 
 45.30  applications received for interconnection and parallel operation 
 45.31  of distributed generation.  These records must include the date 
 45.32  each application is received, documents generated in the course 
 45.33  of processing each application, correspondence regarding each 
 45.34  application, and the final disposition of each application. 
 45.35     (b) By March 30 of each year, every electric utility shall 
 45.36  file with the commission a distributed generation 
 46.1   interconnection report for the preceding calendar year that 
 46.2   identifies each distributed generation facility interconnected 
 46.3   with the utility's distribution system.  The report must list 
 46.4   the new distributed generation facilities interconnected with 
 46.5   the system since the previous year's report, any distributed 
 46.6   generation facilities no longer interconnected with the 
 46.7   utility's system since the previous report, the capacity of each 
 46.8   facility, and the feeder or other point on the company's utility 
 46.9   system where the facility is connected. 
 46.10     (c) The annual report must also identify all applications 
 46.11  for interconnection received during the previous one-year period 
 46.12  and the disposition of those applications. 
 46.13                             ARTICLE 11 
 46.14                       CONFORMING AMENDMENTS 
 46.15     Section 1.  Minnesota Statutes 2000, section 216A.07, 
 46.16  subdivision 3, is amended to read: 
 46.17     Subd. 3.  [INTERVENTION IN COMMISSION PROCEEDING.] The 
 46.18  commissioner may intervene as a party in all proceedings before 
 46.19  the commission.  When intervening in gas or electric hearings, 
 46.20  the commissioner shall prepare and defend testimony designed to 
 46.21  encourage energy conservation improvements as defined in section 
 46.22  216B.241.  The attorney general shall act as counsel in the 
 46.23  proceedings.  
 46.24     Sec. 2.  Minnesota Statutes 2000, section 216B.03, is 
 46.25  amended to read: 
 46.26     216B.03 [REASONABLE RATE.] 
 46.27     Every rate made, demanded, or received by any public 
 46.28  utility, or by any two or more public utilities jointly, shall 
 46.29  be just and reasonable.  Rates shall not be unreasonably 
 46.30  preferential, unreasonably prejudicial or discriminatory, but 
 46.31  shall be sufficient, equitable and consistent in application to 
 46.32  a class of consumers.  To the maximum reasonable extent, the 
 46.33  commission shall set rates to encourage energy conservation and 
 46.34  renewable energy use and to further the goals of sections 
 46.35  216B.164, 216B.241, and 216C.05.  Any doubt as to reasonableness 
 46.36  should be resolved in favor of the consumer.  For rate making 
 47.1   purposes a public utility may treat two or more municipalities 
 47.2   served by it as a single class wherever the populations are 
 47.3   comparable in size or the conditions of service are similar.  
 47.4      Sec. 3.  Minnesota Statutes 2000, section 216B.16, 
 47.5   subdivision 1, is amended to read: 
 47.6      Subdivision 1.  [NOTICE.] Unless the commission otherwise 
 47.7   orders, no public utility shall change a rate which has been 
 47.8   duly established under this chapter, except upon 60 days' notice 
 47.9   to the commission.  The notice shall include statements of 
 47.10  facts, expert opinions, substantiating documents, and exhibits, 
 47.11  supporting the change requested, and state the change proposed 
 47.12  to be made in the rates then in force and the time when the 
 47.13  modified rates will go into effect.  If the filing utility does 
 47.14  not have an approved conservation improvement plan on file with 
 47.15  the department of public service, it shall also include in its 
 47.16  notice an energy conservation plan pursuant to section 
 47.17  216B.241.  The filing utility shall give written notice, as 
 47.18  approved by the commission, of the proposed change to the 
 47.19  governing body of each municipality and county in the area 
 47.20  affected.  All proposed changes shall be shown by filing new 
 47.21  schedules or shall be plainly indicated upon schedules on file 
 47.22  and in force at the time. 
 47.23     Sec. 4.  Minnesota Statutes 2000, section 216B.16, 
 47.24  subdivision 6b, is amended to read: 
 47.25     Subd. 6b.  [ENERGY CONSERVATION IMPROVEMENT.] (a) Except as 
 47.26  otherwise provided in this subdivision, all investments and 
 47.27  expenses of a public utility as defined in section 216B.241, 
 47.28  subdivision 1, paragraph (e), incurred in connection with energy 
 47.29  conservation improvements shall be recognized and included by 
 47.30  the commission in the determination of just and reasonable rates 
 47.31  as if the investments and expenses were directly made or 
 47.32  incurred by the utility in furnishing utility service. 
 47.33     (b) After December 31, 1999, investments and expenses for 
 47.34  energy conservation improvements shall not be included by the 
 47.35  commission in the determination of just and reasonable electric 
 47.36  and gas rates for retail electric and gas service provided to 
 48.1   large electric customer facilities that have been exempted by 
 48.2   the commissioner of the department of public service pursuant to 
 48.3   section 216B.241, subdivision 1a, paragraph (b).  However, no 
 48.4   public utility shall be prevented from recovering its investment 
 48.5   in energy conservation improvements from all customers that were 
 48.6   made on or before December 31, 1999, in compliance with the 
 48.7   requirements of section 216B.241.  
 48.8      (c) The commission may permit a public utility to file rate 
 48.9   schedules providing for annual recovery of the costs of energy 
 48.10  conservation improvements.  These rate schedules may be 
 48.11  applicable to less than all the customers in a class of retail 
 48.12  customers if necessary to reflect the differing minimum spending 
 48.13  requirements of section 216B.241, subdivision 1a.  After 
 48.14  December 31, 1999, the commission shall allow a public utility, 
 48.15  without requiring a general rate filing under this section, to 
 48.16  reduce the electric and gas rates applicable to large electric 
 48.17  customer facilities that have been exempted by the commissioner 
 48.18  of the department of public service pursuant to section 
 48.19  216B.241, subdivision 1a, paragraph (b), by an amount that 
 48.20  reflects the elimination of energy conservation improvement 
 48.21  investments or expenditures for those facilities required on or 
 48.22  before December 31, 1999.  In the event that the commission has 
 48.23  set electric or gas rates based on the use of an accounting 
 48.24  methodology that results in the cost of conservation 
 48.25  improvements being recovered from utility customers over a 
 48.26  period of years, the rate reduction may occur in a series of 
 48.27  steps to coincide with the recovery of balances due to the 
 48.28  utility for conservation improvements made by the utility on or 
 48.29  before December 31, 1999.  
 48.30     Sec. 5.  Minnesota Statutes 2000, section 216B.162, 
 48.31  subdivision 8, is amended to read: 
 48.32     Subd. 8.  [ENERGY EFFICIENCY IMPROVEMENT; EXPENSE 
 48.33  RECOVERY.] If the commission approves a competitive rate or the 
 48.34  parties agree to a modified rate, the commission may require the 
 48.35  electric utility to provide the customer with an energy audit 
 48.36  and assist in implementing cost-effective energy efficiency 
 49.1   improvements to assure that the customer's use of electricity is 
 49.2   efficient.  An investment in cost-effective energy conservation 
 49.3   improvements required under this section must be treated as an 
 49.4   energy conservation improvement program and included in the 
 49.5   department's determination of significant investments under 
 49.6   section 216B.241.  The utility shall recover energy conservation 
 49.7   improvement expenses in a rate proceeding under section 216B.16 
 49.8   or 216B.17 in the same manner as the commission authorizes for 
 49.9   the recovery of conservation expenditures made under section 
 49.10  216B.241. 
 49.11     Sec. 6.  Minnesota Statutes 2000, section 216B.243, 
 49.12  subdivision 3, is amended to read: 
 49.13     Subd. 3.  [SHOWING REQUIRED FOR CONSTRUCTION.] No proposed 
 49.14  large energy facility shall be certified for construction unless 
 49.15  the applicant can show that demand for electricity cannot be met 
 49.16  more cost-effectively through energy conservation and 
 49.17  load-management measures and unless the applicant has otherwise 
 49.18  justified its need.  In assessing need, the commission shall 
 49.19  evaluate: 
 49.20     (1) the accuracy of the long-range energy demand forecasts 
 49.21  on which the necessity for the facility is based; 
 49.22     (2) the effect of existing or possible energy conservation 
 49.23  programs under sections 216C.05 to 216C.30 and this section or 
 49.24  other federal or state legislation on long-term energy demand; 
 49.25     (3) the relationship of the proposed facility to overall 
 49.26  state energy needs, as described in the most recent state energy 
 49.27  policy and conservation report prepared under section 216C.18; 
 49.28     (4) promotional activities that may have given rise to the 
 49.29  demand for this facility; 
 49.30     (5) socially beneficial uses of the output of this 
 49.31  facility, including its uses to protect or enhance environmental 
 49.32  quality; 
 49.33     (6) the effects of the facility in inducing future 
 49.34  development; 
 49.35     (7) possible alternatives for satisfying the energy demand 
 49.36  including but not limited to potential for increased efficiency 
 50.1   of existing energy generation facilities; 
 50.2      (8) the policies, rules, and regulations of other state and 
 50.3   federal agencies and local governments; and 
 50.4      (9) any feasible combination of energy conservation 
 50.5   improvements, required under section 216B.241, that can (i) 
 50.6   replace part or all of the energy to be provided by the proposed 
 50.7   facility, and (ii) compete with it economically. 
 50.8      Sec. 7.  Minnesota Statutes 2000, section 216C.09, is 
 50.9   amended to read: 
 50.10     216C.09 [COMMISSIONER DUTIES.] 
 50.11     (a) The commissioner shall: 
 50.12     (1) manage the department as the central repository within 
 50.13  the state government for the collection of data on energy; 
 50.14     (2) prepare and adopt an emergency allocation plan 
 50.15  specifying actions to be taken in the event of an impending 
 50.16  serious shortage of energy, or a threat to public health, 
 50.17  safety, or welfare; 
 50.18     (3) undertake a continuing assessment of trends in the 
 50.19  consumption of all forms of energy and analyze the social, 
 50.20  economic, and environmental consequences of these trends; 
 50.21     (4) carry out energy conservation measures as specified by 
 50.22  the legislature and recommend to the governor and the 
 50.23  legislature additional energy policies and conservation measures 
 50.24  as required to meet the objectives of sections 216C.05 to 
 50.25  216C.30; 
 50.26     (5) collect and analyze data relating to present and future 
 50.27  demands and resources for all sources of energy; 
 50.28     (6) evaluate policies governing the establishment of rates 
 50.29  and prices for energy as related to energy conservation, and 
 50.30  other goals and policies of sections 216C.05 to 216C.30, and 
 50.31  make recommendations for changes in energy pricing policies and 
 50.32  rate schedules; 
 50.33     (7) study the impact and relationship of the state energy 
 50.34  policies to international, national, and regional energy 
 50.35  policies; 
 50.36     (8) design and implement a state program for the 
 51.1   conservation of energy; this program shall include but not be 
 51.2   limited to, general commercial, industrial, and residential, and 
 51.3   transportation areas; such program shall also provide for the 
 51.4   evaluation of energy systems as they relate to lighting, 
 51.5   heating, refrigeration, air conditioning, building design and 
 51.6   operation, and appliance manufacturing and operation; 
 51.7      (9) inform and educate the public about the sources and 
 51.8   uses of energy and the ways in which persons can conserve 
 51.9   energy; 
 51.10     (10) dispense funds made available for the purpose of 
 51.11  research studies and projects of professional and civic 
 51.12  orientation, which are related to either energy conservation, 
 51.13  resource recovery, or the development of alternative energy 
 51.14  technologies which conserve nonrenewable energy resources while 
 51.15  creating minimum environmental impact; 
 51.16     (11) charge other governmental departments and agencies 
 51.17  involved in energy-related activities with specific information 
 51.18  gathering goals and require that those goals be met; 
 51.19     (12) design a comprehensive program for the development of 
 51.20  indigenous energy resources.  The program shall include, but not 
 51.21  be limited to, providing technical, informational, educational, 
 51.22  and financial services and materials to persons, businesses, 
 51.23  municipalities, and organizations involved in the development of 
 51.24  solar, wind, hydropower, peat, fiber fuels, biomass, and other 
 51.25  alternative energy resources.  The program shall be evaluated by 
 51.26  the alternative energy technical activity; and 
 51.27     (13) dispense loans, grants, or other financial aid from 
 51.28  money received from litigation or settlement of alleged 
 51.29  violations of federal petroleum pricing regulations made 
 51.30  available to the department for that purpose.  The commissioner 
 51.31  shall adopt rules under chapter 14 for this purpose.  Money 
 51.32  dispersed under this clause must not include money received as a 
 51.33  result of the settlement of the parties and order of the United 
 51.34  States District Court for the District of Kansas in the case of 
 51.35  In Re Department of Energy Stripper Well Exemption Litigation, 
 51.36  578 F. Supp. 586 (D.Kan. 1983) and all money received after 
 52.1   August 1, 1988, by the governor, the commissioner of finance, or 
 52.2   any other state agency resulting from overcharges by oil 
 52.3   companies in violation of federal law.  
 52.4      (b) Further, the commissioner may participate fully in 
 52.5   hearings before the public utilities commission on matters 
 52.6   pertaining to rate design, cost allocation, efficient resource 
 52.7   utilization, utility conservation investments, small power 
 52.8   production, cogeneration, and other rate issues.  The 
 52.9   commissioner shall support the policies stated in section 
 52.10  216C.05 and shall prepare and defend testimony proposed to 
 52.11  encourage energy conservation improvements as defined in section 
 52.12  216B.241. 
 52.13     Sec. 8.  Minnesota Statutes 2000, section 216C.18, 
 52.14  subdivision 1a, is amended to read: 
 52.15     Subd. 1a.  [RATE PLAN.] The energy policy and conservation 
 52.16  report shall include a section prepared by the public utilities 
 52.17  commission.  The commission's section shall be prepared in 
 52.18  consultation with the commissioner and shall include, but not be 
 52.19  limited to, all of the following:  
 52.20     (1) a description and analysis of the commission's rate 
 52.21  design policy as it pertains to the goals stated in sections 
 52.22  216B.164, 216B.241, and 216C.05, including a description of all 
 52.23  energy conservation improvements ordered by the commission; and 
 52.24     (2) recommendations to the governor and the legislature for 
 52.25  administrative and legislative actions to accomplish the 
 52.26  purposes of sections 216B.164, 216B.241, and 216C.05. 
 52.27                             ARTICLE 12 
 52.28                        TECHNICAL PROVISIONS 
 52.29     Section 1.  [REPEALER.] 
 52.30     Minnesota Statutes 2000, section 216B.241, is repealed.  
 52.31  Minnesota Rules, parts 7820.1800; 7820.1900; 7820.2000; 
 52.32  7820.2200; and 7820.2300, are repealed. 
 52.33     Sec. 2.  [EFFECTIVE DATE.] 
 52.34     This act is effective the day following final enactment.