as introduced - 82nd Legislature (2001 - 2002) Posted on 12/15/2009 12:00am
1.1 A bill for an act 1.2 relating to energy; establishing a state energy plan 1.3 and promoting energy conservation; making conforming, 1.4 technical, and clarifying changes; amending Minnesota 1.5 Statutes 2000, sections 116C.691, subdivision 2, and 1.6 by adding a subdivision; 116C.692; 116C.779; 216A.07, 1.7 by adding a subdivision; 216B.16, subdivision 6b; 1.8 216B.1621, subdivision 2; 216B.164, subdivisions 3, 4, 1.9 and 6; 216B.241, subdivisions 1, 1a, 1b, 1c, 2, and 1.10 2b; 216B.2421, subdivision 1; 216B.2423, subdivision 1.11 2; 216B.243, subdivision 3; 216C.17, subdivision 3; 1.12 and 216C.41, subdivisions 1, 3, 4, 5, and by adding a 1.13 subdivision; proposing coding for new law in Minnesota 1.14 Statutes, chapters 216B; and 272; proposing coding for 1.15 new law as Minnesota Statutes, chapter 216E; repealing 1.16 Minnesota Statutes 2000, sections 216B.241, 1.17 subdivision 2a; 216B.2422, subdivisions 1, 2, 2a, 4, 1.18 5, and 6; and 216C.18. 1.19 BE IT ENACTED BY THE LEGISLATURE OF THE STATE OF MINNESOTA: 1.20 ARTICLE 1 1.21 STATE ENERGY PLAN 1.22 Section 1. [216E.01] [DEFINITIONS.] 1.23 Subdivision 1. [SCOPE.] The terms used in this chapter 1.24 have the meanings given them in this section. If not defined in 1.25 this section, those terms defined in chapters 216A, 216B, and 1.26 216C also apply to terms used in this chapter. 1.27 Subd. 2. [BIOMASS.] "Biomass" means herbaceous crops, 1.28 trees, agricultural waste, and aquatic plant matter used to 1.29 generate electric energy, but excludes mixed municipal solid 1.30 waste as defined in section 115A.03. 1.31 Subd. 3. [COMMISSION.] "Commission" means the public 1.32 utilities commission. 2.1 Subd. 4. [COMMISSIONER.] "Commissioner" means the 2.2 commissioner of commerce. 2.3 Subd. 5. [DEPARTMENT.] "Department" means the department 2.4 of commerce. 2.5 Subd. 6. [ELECTRIC UTILITY.] "Electric utility" means an 2.6 entity that provides 250,000 kilowatt hours annually to retail 2.7 customers in the state, or that owns or operates an electric 2.8 transmission facility in the state. 2.9 Subd. 7. [ENERGY.] "Energy" means natural gas, 2.10 electricity, and petroleum products. 2.11 Subd. 8. [ENERGY CONSERVATION.] "Energy conservation" 2.12 means demand-side management of energy supplies and includes 2.13 activities that demonstrably reduce present and future demand 2.14 for energy or that result in more efficient use of the same 2.15 amount of energy. 2.16 Subd. 9. [LOW-HEAD HYDROPOWER.] "Low-head hydropower" 2.17 means a hydropower facility that has a head of less than 66 feet. 2.18 Subd. 10. [WIND ENERGY CONVERSION SYSTEM.] "Wind energy 2.19 conversion system" or "WECS" means any device, such as a wind 2.20 charger, windmill, or wind turbine and associated facilities 2.21 that converts wind energy to electrical energy. 2.22 Sec. 2. [216E.02] [ENERGY PLAN.] 2.23 The commissioner shall submit to the commission a proposed 2.24 energy plan by March 1, 2002, and every four years thereafter. 2.25 The plan must: 2.26 (1) identify important trends and issues in energy supply, 2.27 consumption, conservation, and costs; 2.28 (2) set energy goals; and 2.29 (3) develop strategies to meet the goals. 2.30 Sec. 3. [216E.03] [ENERGY PLAN CONTENTS.] 2.31 (a) The energy plan must include: 2.32 (1) the amount and type of projected statewide energy 2.33 consumption over the next ten years; 2.34 (2) a determination of whether and the extent to which 2.35 existing and anticipated energy production and transportation 2.36 facilities will or will not be able to supply needed energy; 3.1 (3) a determination of the potential for conservation to 3.2 meet some or all of the projected need for energy; and 3.3 (4) an assessment of the environmental impact of projected 3.4 energy consumption over the next ten years, determined by the 3.5 commissioner in consultation with other state agencies and other 3.6 interested persons, prepared by the commissioner of the 3.7 pollution control agency, with strategies to mitigate those 3.8 impacts. 3.9 (b) In addition, the plan must include an analysis of the 3.10 technical and economic feasibility of meeting future electric 3.11 energy needs in the state by use of environmentally and 3.12 economically sustainable electric generation. This analysis 3.13 must discuss: 3.14 (1) capacity needs; 3.15 (2) maximum reasonably feasible energy conservation; 3.16 (3) achievable generation and distribution efficiencies; 3.17 (4) the potential role of renewable and sustainable forms 3.18 of energy and general cost projections; 3.19 (5) the costs associated with less environmentally damaging 3.20 sources of electric energy; 3.21 (6) the need for changes in transmission capability to 3.22 deliver electricity to consumers; 3.23 (7) whether and to what extent more distributed generation 3.24 can lessen the need for long distance transmission of power; 3.25 (8) the costs, benefits, and future economic impact of 3.26 importing energy into the state and of exporting energy 3.27 generated in the state; 3.28 (9) the costs and benefits of immediate investment in 3.29 renewable energy sources and modern energy technology; and 3.30 (10) the potential for additional streamlining of state and 3.31 local procedures for siting, permitting, and constructing energy 3.32 facilities. 3.33 Sec. 4. [216E.04] [ENERGY GOALS.] 3.34 (a) The plan must establish statewide goals and list 3.35 strategies to accomplish the following goals for: 3.36 (1) energy conservation; 4.1 (2) limiting adverse environmental emissions from the 4.2 generation of electric energy consumed in the state; 4.3 (3) production of electric energy consumed in the state 4.4 from renewable energy sources; 4.5 (4) deployment of distributed electric generation 4.6 technologies; and 4.7 (5) ensuring that energy service is affordable and 4.8 available to all consumers in the state. 4.9 (b) In addition, the plan must: 4.10 (1) identify electric transmission inadequacies and 4.11 alternative means of addressing those inadequacies; 4.12 (2) identify geographic areas that contain critical habitat 4.13 or are in bird migratory pathways and that, therefore, are not 4.14 desirable locations for wind energy conversion systems (WECS); 4.15 and 4.16 (3) set technical standards for WECS installations of five 4.17 megawatts through 30 megawatts nameplate capacity. 4.18 (c) The goals adopted in the plan may be one-time goals or 4.19 a series of goals to meet overall objectives. 4.20 Sec. 5. [216E.05] [ENERGY POLICY GUIDELINES.] 4.21 (a) In setting energy policy goals under section 216E.03, 4.22 the highest priority is energy conservation. The following 4.23 electric energy sources are listed in their descending order of 4.24 preference: 4.25 (1) wind and solar; 4.26 (2) biomass and low-head or refurbished hydropower; 4.27 (3) decomposition gases produced by solid waste management 4.28 facilities, natural gas-fired cogeneration, and waste materials 4.29 or byproducts combined with natural gas; 4.30 (4) natural gas, hydropower that is not low-head or 4.31 refurbished hydropower, and solid waste as a direct fuel or 4.32 refuse-derived fuel; and 4.33 (5) coal and nuclear power. 4.34 (b) In paragraph (a), clauses (3) and (4), use of waste 4.35 materials must be limited to those waste materials and 4.36 byproducts necessarily generated or produced by efficient 5.1 processes and systems. Prevention or minimizing waste and 5.2 byproducts are preferred over relying on continued generation of 5.3 waste materials and byproducts. Within each clause in paragraph 5.4 (a), the more efficient technology that generates electric 5.5 energy, particularly a technology that captures and reuses waste 5.6 heat, is preferred over other technologies listed in each clause 5.7 of paragraph (a). 5.8 Sec. 6. [216E.06] [PLAN DEVELOPMENT AND APPROVAL.] 5.9 Subdivision 1. [CONSULTATION.] In preparing the proposed 5.10 energy plan, the commissioner shall consult with: 5.11 (1) the commissioners of agriculture, economic security, 5.12 health, natural resources, and the pollution control agency; 5.13 (2) the office of strategic and long-range planning; 5.14 (3) academic and other energy planning experts; 5.15 (4) regional energy infrastructure planning groups; 5.16 (5) energy utilities and other energy service providers; 5.17 (6) public interest advocacy groups; and 5.18 (7) other interested persons. 5.19 Subd. 2. [PUBLIC PARTICIPATION.] The commissioner shall: 5.20 (1) invite public comment and participation during plan 5.21 development; 5.22 (2) hold at least one public meeting on the proposed plan 5.23 in each energy infrastructure planning region of the state after 5.24 at least 30 days public notice in the region; and 5.25 (3) provide participant assistance by making assessments in 5.26 addition to biennial appropriations under section 216B.62. 5.27 Participant assistance is limited to $10,000 per participant and 5.28 a total of $200,000 in each four-year planning cycle. The 5.29 commissioner must find that a person or group that requests 5.30 assistance can materially assist in developing the plan and 5.31 likely would not be able to participate effectively without the 5.32 assistance. 5.33 Subd. 3. [INFORMATION.] To develop the initial plan, the 5.34 commissioner shall rely on information in the most recent 5.35 integrated resource plan approved by the public utilities 5.36 commission for each energy utility or, in the case of a 6.1 municipal utility or a cooperative electric association, filed 6.2 with the commission. For future proposed plans, the 6.3 commissioner shall rely on information contained in energy 6.4 utility compliance plans and progress reports. Each energy 6.5 utility or energy service provider in the state shall comply 6.6 with additional requests for information that the commissioner 6.7 deems necessary to complete the proposed plan. In addition, the 6.8 commissioner shall gather information from any other relevant 6.9 sources, including, but not limited to, regional and national 6.10 reliability organizations, regional and national transmission 6.11 organizations, regional energy infrastructure planning groups, 6.12 energy trade associations, and energy research entities. 6.13 Subd. 4. [NOTICE AND COMMENT; PLAN APPROVAL.] The public 6.14 utilities commission shall approve, or approve with 6.15 modifications, the energy plan by September 1, 2002, and every 6.16 four years thereafter. The commission shall provide public 6.17 notice of any meetings to discuss the proposed plan and allow 6.18 opportunity for written comment prior to making its decision. 6.19 The commission shall publish in the State Register its order 6.20 approving the final energy plan. 6.21 Sec. 7. [216E.07] [REGIONAL ENERGY INFRASTRUCTURE 6.22 PLANNING.] 6.23 Subdivision 1. [ESTABLISHING PLANNING REGIONS.] The 6.24 commission, after notice and opportunity for written comment, 6.25 shall establish geographic regional energy infrastructure 6.26 planning regions in the state by October 1, 2001. Planning 6.27 regions shall coincide, if feasible, with existing subregional 6.28 planning areas used by the regional electric reliability or 6.29 regional transmission organization serving Minnesota. 6.30 Subd. 2. [PLANNING GROUP.] Each energy utility that 6.31 operates in an identified region shall participate in the 6.32 regional energy infrastructure planning group. Each regional 6.33 group must include as voting members, at a minimum, 6.34 representatives of energy utilities, public interest groups, and 6.35 local governments. 6.36 Subd. 3. [PUBLIC MEETINGS.] Each regional energy 7.1 infrastructure planning group shall hold public meetings within 7.2 the region on a regular basis and provide public notice at least 7.3 14 calendar days in advance of a meeting. 7.4 Subd. 4. [REPORT.] By December 31, 2001, and every two 7.5 years thereafter, each regional energy infrastructure planning 7.6 group shall submit a report to the commission and the department 7.7 that: 7.8 (1) identifies inadequacies in electric generation and 7.9 transmission within the region; 7.10 (2) lists alternative ways to address identified 7.11 inadequacies in priority order consistent with the guidelines in 7.12 section 216E.05 and, for reports in years after 2001, the 7.13 existing statewide energy plan approved by the commission under 7.14 section 216E.06, subdivision 4; and 7.15 (3) identifies potential general and, to the extent known, 7.16 specific economic, environmental, and social issues associated 7.17 with each alternative. 7.18 Sec. 8. [216E.08] [ELECTRIC UTILITY COMPLIANCE PLANS.] 7.19 Subdivision 1. [COMPLIANCE PLAN FILING.] By March 15, 7.20 2003, and every four years thereafter, each electric utility 7.21 shall file with the commission a plan that identifies how the 7.22 utility will comply with the goals of the statewide energy plan 7.23 and meet the energy needs of its customers. Each compliance 7.24 plan must: 7.25 (1) describe in summary form the utility's existing energy 7.26 resources and transmission and delivery system; 7.27 (2) forecast the electric energy needs of the electric 7.28 utility's customers over the next ten years; 7.29 (3) identify deficiencies in the utility's energy resources 7.30 and transmission and distribution capacity to meet the needs of 7.31 its customers over the ten-year period; 7.32 (4) propose projects to meet the identified deficiencies 7.33 that are consistent with the statewide energy plan, goals, and 7.34 guidelines under sections 216E.01 to 216E.06; 7.35 (5) explain how the energy utility utilized the regional 7.36 energy infrastructure planning group process to arrive at its 8.1 deficiency determinations and project proposals and how, and to 8.2 what extent, the utility sought and considered public 8.3 participation in making its determinations and proposals; 8.4 (6) how the proposed projects provide the most reasonably 8.5 minimal adverse environmental and social impacts for the most 8.6 reasonably minimal costs, utilizing environmental and 8.7 socioeconomic cost values established by the commission and 8.8 other relevant data and information; and 8.9 (7) for compliance plans subsequent to the first one, 8.10 report on progress made in implementing its previous compliance 8.11 plan. 8.12 Subd. 2. [JOINT PLANS.] A generation and transmission 8.13 organization or any other organization or group may submit a 8.14 compliance plan on behalf of one or more municipal or rural 8.15 electric cooperative utilities. One or more public utilities 8.16 may submit a joint compliance plan. 8.17 Sec. 9. [216E.09] [COMPLIANCE PLAN REVIEW.] 8.18 Subdivision 1. [COMMISSION REVIEW AND DECISION.] The 8.19 commission shall review an electric utility's compliance plan, 8.20 after providing notice and opportunity for written comment. 8.21 Within 120 days of receipt of a plan, the commission shall 8.22 approve it if it meets the standards in subdivision 2 or, if it 8.23 does not meet the standards, the commission shall: 8.24 (1) for a plan submitted by a municipal or rural electric 8.25 cooperative utility, refer the compliance plan back to the 8.26 governing board of the utility; or 8.27 (2) for a plan submitted by a public utility or other 8.28 entity, modify or reject the plan and require resubmission of a 8.29 plan that complies with the standards. 8.30 Subd. 2. [COMMISSION REVIEW STANDARDS.] The public 8.31 utilities commission shall consider whether the electric utility 8.32 has demonstrated that: 8.33 (1) sufficient public input was incorporated into the 8.34 planning process; 8.35 (2) if the electric utility implements the plan, it will 8.36 comply with the energy plan approved under section 216E.06; and 9.1 (3) if the utility implements the plan, it will meet the 9.2 energy needs of the utility's customers in an economically and 9.3 environmentally sound and sustainable manner. 9.4 Sec. 10. [216E.10] [DEMONSTRATING PLAN PROGRESS.] 9.5 By March 1, 2005, and every four years thereafter, each 9.6 electric utility shall provide the commission and the department 9.7 an interim report that identifies progress it has made to 9.8 implement its most recently approved compliance plan, problems 9.9 that have arisen, barriers to implementation, and any necessary 9.10 proposals to modify its compliance plan. If the report proposes 9.11 to modify the compliance plan, the commission shall follow the 9.12 procedures and standards in section 216E.09. 9.13 Sec. 11. [216E.11] [DEFICIENCY.] 9.14 Subdivision 1. [DEFINITION.] "Deficiency" means a 9.15 condition, or set of conditions, that materially limit the 9.16 adequacy of electric supply, efficiency of electric service, or 9.17 reliability of electric service to an electric utility's 9.18 customers in the state that may require construction of a 9.19 generation or transmission project. 9.20 Subd. 2. [NOTICE.] (a) An electric utility that identifies 9.21 a deficiency shall give notice of the deficiency to at least: 9.22 (1) the members of affected regional energy infrastructure 9.23 planning groups; 9.24 (2) any potentially affected landowners; and 9.25 (3) other interested persons, including officials of 9.26 potentially affected local governments. 9.27 (b) Notice of deficiency must be made before submitting a 9.28 request for approval of an energy project to any governmental 9.29 entity. The energy utility may identify a deficiency as part of 9.30 a compliance plan, a progress report, or independently of either 9.31 and may submit a compliance plan or progress report as notice of 9.32 the deficiency as long as the deficiency and its implications 9.33 are clearly noted in a summary preceding the body of the 9.34 document. 9.35 Sec. 12. [216E.12] [PUBLIC PURPOSE ENERGY PROJECTS.] 9.36 Subdivision 1. [LIST.] The commission shall maintain a 10.1 list of public purpose energy projects. Projects qualify for 10.2 the list upon approval by the commission under subdivision 4, 10.3 except a wind energy conversion system with a combined nameplate 10.4 capacity of 30 megawatts or less is a public purpose project if 10.5 it meets the requirements of subdivision 6. 10.6 Subd. 2. [BENEFITS.] (a) Notwithstanding any other law to 10.7 the contrary, eminent domain powers may be used for an energy 10.8 project only if it is on the public purpose energy projects list. 10.9 (b) In siting and routing a public purpose project, the 10.10 environmental quality board and any permitting entity may not 10.11 consider the "no build" alternative in environmental review or 10.12 in evaluating and considering permits under section 116D.04, 10.13 subdivision 6. 10.14 (c) A public purpose project is exempt from the certificate 10.15 of need requirement in section 216B.243. 10.16 (d) A public purpose project is eligible for reasonable 10.17 accelerated depreciation to be determined by the commission. 10.18 Subd. 3. [DEFICIENCY CERTIFICATION; PUBLIC PURPOSE ENERGY 10.19 PROJECT.] (a) A person who desires to place a proposed energy 10.20 project on the public purpose energy project list shall file 10.21 with the commission, the department, and any relevant regional 10.22 energy infrastructure planning group, an application for 10.23 certification of the deficiency the project is designed to 10.24 address and, at the same time or a later time, a request to add 10.25 the proposed project to the list. If the request is solely to 10.26 certify a deficiency, the commission shall do so unless: 10.27 (1) the alleged deficiency has not been identified in the 10.28 statewide energy plan, an electric utility compliance plan or 10.29 progress report, or a regional energy infrastructure planning 10.30 group report; 10.31 (2) is inconsistent with any plan or report; or 10.32 (3) is not supported by evidence submitted with the request. 10.33 (b) The commission shall make a determination to accept, 10.34 modify, or reject certification of a deficiency within 60 days 10.35 of a filing, unless another party challenges the deficiency, in 10.36 which case the commission shall establish an expedited contested 11.1 issue procedure not to exceed 120 days. 11.2 Subd. 4. [PUBLIC PURPOSE PROJECT CRITERIA.] The electric 11.3 utility shall demonstrate that a project is a public purpose 11.4 project. The commission may find that a project is a public 11.5 purpose project only if the project addresses a certifiable or 11.6 previously certified deficiency and is consistent with the 11.7 energy policy plan approved under section 216E.06. The 11.8 commission may not place a project on the list if a project that 11.9 is preferred to the proposed project under section 216E.05 is 11.10 shown by any person to be reasonably feasible and comparably 11.11 economic. 11.12 Subd. 5. [DESIGNATING PUBLIC PURPOSE PROJECTS.] (a) The 11.13 commission shall decide whether a project is a public purpose 11.14 project within 120 days of application by an electric utility. 11.15 The commission shall provide notice and an opportunity for 11.16 written comment. Any relevant regional energy infrastructure 11.17 planning group shall comment on alternatives available to 11.18 address the deficiency and recommend whether to place the 11.19 project on the list within 90 days of the date the application 11.20 was filed. Failure of a planning group to comment neither 11.21 supports nor opposes the listing of the project. 11.22 (b) The commission may provide participant assistance by 11.23 making additional assessments under section 216B.62. 11.24 Participant assistance is limited to $10,000 per participant and 11.25 a total of $50,000 per proceeding. The commissioner must find 11.26 that a person or group that requests assistance can materially 11.27 assist the commission in making a determination and likely would 11.28 not be able to participate effectively without the assistance. 11.29 Subd. 6. [PUBLIC PURPOSE WECS.] (a) A wind energy 11.30 conversion system (WECS) with a combined nameplate capacity of 11.31 30 megawatts or less is a public purpose energy project if: 11.32 (1) it is not proposed to be located in an area identified 11.33 in the energy plan adopted under section 216E.06 as containing 11.34 critical habitat or in a bird migratory pathway; and 11.35 (2) the project proposer notifies the commission, the 11.36 commissioners of commerce and natural resources, and the 12.1 environmental quality board of the proposed project and has not 12.2 received a written objection to the project within 45 days of 12.3 delivery of the notice. An objection must be sent to the 12.4 project proposer and all other state agencies listed above. 12.5 (b) If a written objection is made to a proposed WECS 12.6 project, the procedure in subdivision 5 applies to determine 12.7 whether the proposed project qualifies for the public purpose 12.8 projects list. 12.9 (c) Placement of a WECS with a combined nameplate capacity 12.10 of 30 megawatts or less on the public purpose energy projects 12.11 list supersedes and preempts all other state permitting 12.12 processes and all zoning, building, or land use rules, 12.13 regulations, or ordinances adopted by regional, county, local, 12.14 and special purpose governments. 12.15 Sec. 13. [REPEALER.] 12.16 Minnesota Statutes 2000, sections 216B.2422, subdivisions 12.17 1, 2, 2a, 4, 5, and 6; and 216C.18, are repealed. 12.18 ARTICLE 2 12.19 ENERGY CONSERVATION 12.20 Section 1. Minnesota Statutes 2000, section 216B.241, 12.21 subdivision 1, is amended to read: 12.22 Subdivision 1. [DEFINITIONS.] For purposes of this section 12.23 and section 216B.16, subdivision 6b, the terms defined in this 12.24 subdivision have the meanings given them. 12.25 (a) "Commission" means the public utilities commission. 12.26 (b) "Commissioner" means the commissioner of
public service12.27 commerce. 12.28 (c) "Customer facility" means all buildings, structures, 12.29 equipment, and installations at a single site. 12.30 (d) "Department" means the department of public12.31 servicecommerce. 12.32 (e) "Energy conservation" means demand-side management of 12.33 energy supplies and includes activities that demonstrably reduce 12.34 present and future demand for energy or that result in more 12.35 efficient use of the same amount of energy. Load management 12.36 that does not reduce actual overall energy demand is not energy 13.1 conservation. 13.2 (f) "Energy conservation improvement" means the purchase or13.3 installation of a device, method, material, or project that:13.4 (1) reduces consumption of or increases efficiency in the13.5 use of electricity or natural gas, including but not limited to13.6 insulation and ventilation, storm or thermal doors or windows,13.7 caulking and weatherstripping, furnace efficiency modifications,13.8 thermostat or lighting controls, awnings, or systems to turn off13.9 or vary the delivery of energy;a tangible or intangible 13.10 improvement that results in energy conservation. 13.11 (2) creates, converts, or actively uses energy from13.12 renewable sources such as solar, wind, and biomass, provided13.13 that the device or method conforms with national or state13.14 performance and quality standards whenever applicable;13.15 (3) seeks to provide energy savings through reclamation or13.16 recycling and that is used as part of the infrastructure of an13.17 electric generation, transmission, or distribution system within13.18 the state or a natural gas distribution system within the state;13.19 or13.20 (4) provides research or development of new means of13.21 increasing energy efficiency or conserving energy or research or13.22 development of improvement of existing means of increasing13.23 energy efficiency or conserving energy.13.24 (f)(g) "Investments and expenses of a public utility" 13.25 includes the investments and expenses incurred by a public 13.26 utility in connection with an energy conservation improvement, 13.27 including but not limited to: 13.28 (1) the differential in interest cost between the market 13.29 rate and the rate charged on a no-interest or below-market 13.30 interest loan made by a public utility to a customer for the 13.31 purchase or installation of an energy conservation improvement; 13.32 (2) the difference between the utility's cost of purchase 13.33 or installation of energy conservation improvements and any 13.34 price charged by a public utility to a customer for such 13.35 improvements. 13.36 (g)(h) "Large electric customer facility" means a customer 14.1 facility that imposes a peak electrical demand on an electric 14.2 utility's system of not less than 20,000 kilowatts, measured in 14.3 the same way as the utility that serves the customer facility 14.4 measures electrical demand for billing purposes, and for which 14.5 electric services are provided at retail on a single bill by a 14.6 utility operating in the state. 14.7 Sec. 2. Minnesota Statutes 2000, section 216B.241, 14.8 subdivision 1a, is amended to read: 14.9 Subd. 1a. [INVESTMENT, EXPENDITURE, AND CONTRIBUTION; 14.10 PUBLIC UTILITY.] (a) For purposes of this subdivision and 14.11 subdivision 2, "public utility" has the meaning given it in 14.12 section 216B.02, subdivision 4. Each public utility shall spend 14.13 and invest for energy conservation improvements under this 14.14 subdivision and subdivision 2 the following amounts: 14.15 (1) for a utility that furnishes gas service, 0.5 percent 14.16 of its gross operating revenues from service provided in the 14.17 state; 14.18 (2) for a utility that furnishes electric service, 1.5 14.19 percent of its gross operating revenues from service provided in 14.20 the state; and 14.21 (3) for a utility that furnishes electric service and that 14.22 operates a nuclear-powered electric generating plant within the 14.23 state, two percent of its gross operating revenues from service 14.24 provided in the state. 14.25 For purposes of this paragraph (a), "gross operating revenues" 14.26 do not include revenues from large electric customer facilities 14.27 exempted by the commissioner of the department of public service14.28 pursuant tounder paragraph (b). 14.29 (b) The owner of a large electric customer facility may 14.30 petition the commissioner of the department of public14.31 servicecommission to exempt both electric and gas utilities 14.32 serving the large energy customer facility from the investment 14.33 and expenditure requirements of paragraph (a) with respect to 14.34 retail revenues attributable to the facility. At a minimum, the 14.35 petition must be supported by evidence relating to competitive 14.36 or economic pressures on the customer and a showing by the 15.1 customer of reasonable efforts to identify, evaluate, and 15.2 implement cost-effective conservation improvements at the 15.3 facility. If a petition is filed on or before October 1 of any 15.4 year, the order of the commissionercommission to exempt 15.5 revenues attributable to the facility can be effective no 15.6 earlier than January 1 of the following year. The commissioner15.7 commission shall not grant an exemption if the commissioner15.8 commission determines that granting the exemption is contrary to 15.9 the public interest. The commissionercommission may, on 15.10 request of any person or on its own motion and after 15.11 investigation by the department, rescind any exemption granted 15.12 under this paragraph upon a determination that cost-effective 15.13 energy conservation improvements are available at the large 15.14 electric customer facility. For the purposes of this paragraph, 15.15 "cost-effective" means that the projected total cost of the 15.16 energy conservation improvement at the large electric customer 15.17 facility is less than the projected present value of the energy 15.18 and demand savings resulting from the energy conservation 15.19 improvement. For the purposes of investigations by the 15.20 commissionerdepartment under this paragraph, the owner of any 15.21 large electric customer facility shall, upon request, provide 15.22 the commissionerdepartment with updated information comparable 15.23 to that originally supplied in or with the owner's original 15.24 petition under this paragraph. 15.25 (c) The commissionercommission may require investments or 15.26 spending greater than the amounts required under this 15.27 subdivision for a public utility whose most recent advance 15.28 forecast required under section 216B.2422 or216C.17 or 216E.08 15.29 projects a peak demand deficit of 100 megawatts or greater 15.30 within five years under mid-range forecast assumptions. 15.31 (d) A public utility or owner of a large electric customer15.32 facility may appeal a decision of the commissioner under15.33 paragraph (b) or (c) to the commission under subdivision 2. In15.34 reviewing a decision of the commissioner under paragraph (b) or15.35 (c), the commission shall rescind the decision if it finds that15.36 the required investments or spending will:16.1 (1) not result in cost-effective energy conservation16.2 improvements; or16.3 (2) otherwise not be in the public interest.16.4 (e) Each utility shall determine what portion of the amount16.5 it sets aside for conservation improvement will be used for16.6 conservation improvements under subdivision 2 and what portion16.7 it will contribute to the energy and conservation account16.8 established in subdivision 2a. A public utility may propose to16.9 the commissioner to designate that all or a portion of funds16.10 contributed to the account established in subdivision 2a be used16.11 for research and development projects. Contributions must be16.12 remitted to the commissioner of public service by February 1 of16.13 each year.Nothing in this subdivision prohibits a public 16.14 utility from spending or investing for energy conservation 16.15 improvement more than required in this subdivision. 16.16 Sec. 3. Minnesota Statutes 2000, section 216B.241, 16.17 subdivision 1b, is amended to read: 16.18 Subd. 1b. [CONSERVATION IMPROVEMENT BY COOPERATIVE 16.19 ASSOCIATION OR MUNICIPALITY.] (a) This subdivision applies to: 16.20 (1) a cooperative electric association that generates and16.21 transmits electricity to associations that provide electricity16.22 at retail including a cooperative electric association not16.23 located in this state that serves associations or others in the16.24 stateprovides retail electric service to its members; 16.25 (2) a municipality that provides electric service to retail 16.26 customers; and 16.27 (3) a municipality with gross operating revenues in excess 16.28 of $5,000,000 from sales of natural gas to retail customers. 16.29 (b) Each cooperative electric association and municipality 16.30 subject to this subdivision shall spend and invest for energy 16.31 conservation improvements under this subdivision the following 16.32 amounts: 16.33 (1) for a municipality, 0.5 percent of its gross operating 16.34 revenues from the sale of gas and one percent of its gross 16.35 operating revenues from the sale of electricity not purchased16.36 from a public utility governed by subdivision 1a or a17.1 cooperative electric association governed by this subdivision,17.2 excluding gross operating revenues from electric and gas service17.3 provided in the state to large electric customer facilities; and 17.4 (2) for a cooperative electric association, 1.5 percent of 17.5 its gross operating revenues from service provided in the state ,17.6 excluding gross operating revenues from service provided in the17.7 state to large electric customer facilities indirectly through a17.8 distribution cooperative electric association. 17.9 (c) Each municipality and cooperative electric association 17.10 subject to this subdivision shall identify and implement energy 17.11 conservation improvement spending and investments that are 17.12 appropriate for the municipality or association, except that a 17.13 municipality or association may not spend or invest for energy 17.14 conservation improvements that directly benefit a large electric 17.15 customer facility for which the commission has issued an 17.16 exemption under subdivision 1a, paragraph (b). Each 17.17 municipality and cooperative electric association subject to 17.18 this subdivision may spend and invest annually up to 15 percent 17.19 of the total amount required to be spent and invested on energy 17.20 conservation improvements under this subdivision on research and 17.21 development projects that meet the definition ofrelated to 17.22 energy conservation improvement in subdivision 117.23 andimprovements that are funded directly by the municipality or 17.24 cooperative electric association. Load management may be used17.25 to meet the requirements of this subdivision if it reduces the17.26 demand for or increases the efficiency of electric services.A 17.27 generation and transmission cooperative electric association may17.28 include as spending and investment required under this17.29 subdivision conservation improvement spending and investment by17.30 that provides energy services to cooperative electric 17.31 associations that provide electric service at retail to 17.32 consumers and that are served by the generation and transmission17.33 associationmay invest in energy conservation improvements on 17.34 behalf of the associations it serves under an agreement between 17.35 the generation and transmission cooperative and each cooperative 17.36 electric association for funding the investments. 18.1 (d) By February 1 of each year, each municipality or 18.2 cooperative shall report to the commissionerdepartment its 18.3 energy conservation improvement spending and investments with a18.4 brief analysis of effectiveness in reducing consumption of18.5 electricity or gas. The report must specify the actual energy 18.6 savings or increased efficiency in the use of electricity within 18.7 the service territory of the municipality or association that is 18.8 the result of the spending and investments. The commissioner18.9 department shall review each report and make recommendations, 18.10 where appropriate, to the municipality or association to 18.11 increase the effectiveness of conservation improvement 18.12 activities. The commissionerdepartment shall also review each 18.13 report for whether a portion of the money spent on residential 18.14 conservation improvement programs is devoted to programs that 18.15 directly address the needs of renters and low-income persons 18.16 unless an insufficient number of appropriate programs are18.17 available. For the purposes of this subdivision and subdivision 18.18 2, "low-income" means an income of less than 185 percent of the 18.19 federal poverty level. 18.20 (e) As part of its spending for conservation improvement, a18.21 municipality or association may contribute to the energy and18.22 conservation account. A municipality or association may propose18.23 to the commissioner to designate that all or a portion of funds18.24 contributed to the account be used for research and development18.25 projects. Any amount contributed must be remitted to the18.26 commissioner of public service by February 1 of each year.18.27 Sec. 4. Minnesota Statutes 2000, section 216B.241, 18.28 subdivision 1c, is amended to read: 18.29 Subd. 1c. [ ENERGY-SAVINGENERGY-CONSERVATION GOALS.] The18.30 commissioner shall establish energy-saving goals for energy18.31 conservation improvement expenditures and shall evaluate an18.32 energy conservation improvement program on how well it meets the18.33 goals set.(a) To the extent that an energy service provider 18.34 required to spend for or invest in energy conservation under 18.35 this section chooses to continue to directly spend for or invest 18.36 in conservation improvements until the final transition of 19.1 conservation funds to an energy efficiency utility under section 19.2 216B.2411, the service provider shall design and implement 19.3 energy conservation improvement programs that will and do result 19.4 in achieving the interim energy conservation goals developed 19.5 under the energy plan required in chapter 216E. As part of that 19.6 plan, the department shall recommend and the commission shall 19.7 adopt energy savings goals for each energy service provider that 19.8 will apply during the transition to full funding of one or more 19.9 energy efficiency utilities. The total of the individual goals 19.10 must equal the statewide goals established by the plan. To 19.11 determine the prorated goals for each individual service 19.12 provider, the department and commission shall determine the 19.13 general potential for energy conservation within each service 19.14 territory based on: 19.15 (1) the percentage of the state's energy consumers within 19.16 the territory; 19.17 (2) the level of verifiable energy savings achieved over 19.18 the most recent five-year period within the territory; 19.19 (3) the relative mix of customer classes within the service 19.20 territory in light of the potential for energy savings from 19.21 each; 19.22 (4) the relative types, sizes, and ages of structures 19.23 within the service territory; and 19.24 (5) other factors relevant to energy conservation measures 19.25 already in place and the potential for future energy savings 19.26 within the service territory. 19.27 (b) Each energy service provider subject to this section 19.28 shall provide, in biennial conservation filings for public 19.29 utilities or in annual reports for municipal utilities and 19.30 cooperative electric associations, information sufficient for 19.31 making the determinations required under this section. When 19.32 additional information is requested by the department or 19.33 commission, the service provider shall provide the information 19.34 in a timely manner not to exceed 15 working days. 19.35 Sec. 5. Minnesota Statutes 2000, section 216B.241, 19.36 subdivision 2, is amended to read: 20.1 Subd. 2. [PROGRAMS.] (a) The commissionercommission may 20.2 by rulerequire public utilities to make investments and 20.3 expenditures in energy conservation improvements , explicitly20.4 setting forth the interest rates, prices, and terms under which20.5 the improvements must be offered to the customersunder 20.6 department rules in effect on December 31, 2000. The required 20.7 programs must cover a two-year period, except for the transition 20.8 period under section 216B.2411, a public utility may opt to 20.9 propose to alter, add, or delete programs on an annual basis in 20.10 coordination with the energy efficiency utility and the 20.11 department. The commissioner shallcommission may require at20.12 least onea public utility to establish a pilot program touse 20.13 energy conservation improvement funds to make investments in and 20.14 expenditures for energy from renewable resources such as solar, 20.15 wind, or biomass and shall give special consideration and 20.16 encouragement to programs that bring about significant net 20.17 savings through the use of energy-efficient lighting. 20.18 The commissionerdepartment shall evaluate the program on the 20.19 basis of cost-effectiveness and the reliability of technologies20.20 employedthe actual energy conserved, the unit costs to conserve 20.21 the energy in relation to the unit costs to produce, transport, 20.22 and deliver energy from a new supply, including environmental 20.23 and socioeconomic costs, and shall make recommendations to the 20.24 commission for approval, modification, or rejection. The rules20.25 of the department mustcommission shall provide to the extent 20.26 practicable for a free choice, by consumers participating in the 20.27 program, of the device, method, material, or project 20.28 constituting the energy conservation improvement and for a free 20.29 choice of the seller, installer, or contractor of the energy 20.30 conservation improvement ,; provided that, the device, method, 20.31 material, or project seller, installer, or contractor is duly 20.32 licensed, certified, approved, or qualified, including under the 20.33 residential conservation services program, where applicable. 20.34 (b) The commissionercommission may require a utility to 20.35 make an energy conservation improvement investment or 20.36 expenditure proposed by any person whenever the commissionerit 21.1 finds that the improvement will result in energy savings at a 21.2 total cost to the utility less than the cost to the utility to 21.3 produce or purchase an equivalent amount of new supply of 21.4 energy. The commissioner shall nevertheless ensure thatEvery 21.5 public utility shall operate one or more conservation 21.6 improvement programs under periodic review by the department.21.7 Load management may be used to meet the requirements for energy21.8 conservation improvements under this section if it results in a21.9 demonstrable reduction in consumption of energyuntil the end of 21.10 the transition period in section 216B.2411 unless the utility 21.11 opts to accelerate the transfer of funds to one or more energy 21.12 efficiency utilities, in which case the public utility is no 21.13 longer subject to this section once its entire allocated portion 21.14 of the total statewide conservation expenditure is transferred. 21.15 Each public utility subject to subdivision 1a may spend and 21.16 invest annually up to 15 percent of the total amount required to 21.17 be spent and invested on energy conservation improvements under 21.18 this section by the utility on research and development projects 21.19 that meet the definition ofrelated to energy 21.20 conservation improvement in subdivision 1 andimprovements that 21.21 are funded directly by the public utility. A public utility may 21.22 not spend for or invest in energy conservation improvements that 21.23 directly benefit a large electric customer facility for which 21.24 the commissioner, prior to July 1, 2001, or the commission has 21.25 issued an exemption pursuant to subdivision 1a, paragraph (b). 21.26 The commissionercommission shall consider and may require a 21.27 utility to undertake a program suggested by the department, the 21.28 attorney general, or an outside source, including a political 21.29 subdivision or a nonprofit or community organization or any 21.30 other person. 21.31 (c) No utility may make an energy conservation improvement21.32 under this section to a building envelope unless:21.33 (1) it is the primary supplier of energy used for either21.34 space heating or cooling in the building;21.35 (2) the commissioner determines that special circumstances,21.36 that would unduly restrict the availability of conservation22.1 programs, warrant otherwise; or22.2 (3) the utility has been awarded a contract under22.3 subdivision 2a.22.4 (d)The commissionercommission shall ensure that a portion 22.5 of the money spent on residential conservation improvement 22.6 programs is devoted to programs that directly address the needs 22.7 of renters and low-income persons unless an insufficient number22.8 of appropriate programs are available. 22.9 (e) A utility, a political subdivision, or a nonprofit or22.10 community organization that has suggested a program, the22.11 attorney general acting on behalf of consumers and small22.12 business interests, or a utility customer that has suggested a22.13 program and is not represented by the attorney general under22.14 section 8.33 may petition the commission to modify or revoke a22.15 department decision under this section, and the commission may22.16 do so if it determines that the program is not cost-effective,22.17 does not adequately address the residential conservation22.18 improvement needs of low-income persons, has a long-range22.19 negative effect on one or more classes of customers, or is22.20 otherwise not in the public interest. The person petitioning22.21 for commission review has the burden of proof. The commission22.22 shall reject a petition that, on its face, fails to make a22.23 reasonable argument that a program is not in the public interest.22.24 Sec. 6. Minnesota Statutes 2000, section 216B.241, 22.25 subdivision 2b, is amended to read: 22.26 Subd. 2b. [RECOVERY OF EXPENSES.] The commission shall 22.27 allow a utility to recover expenses resulting from a 22.28 conservation improvement program required by the department and22.29 contributions to the energy and conservation account, unless the 22.30 recovery would be inconsistent with a financial incentive 22.31 proposal approved by the commission. In addition, a utility may 22.32 file annually, or the public utilities commission may require 22.33 the utility to file, and the commission may approve, rate 22.34 schedules containing provisions for the automatic adjustment of 22.35 charges for utility service in direct relation to changes in the 22.36 expenses of the utility for real and personal property taxes, 23.1 fees, and permits, the amounts of which the utility cannot 23.2 control. A public utility is eligible to file for adjustment 23.3 for real and personal property taxes, fees, and permits under 23.4 this subdivision only if, in the year previous to the year in 23.5 which it files for adjustment, it has spent or invested at least 23.6 1.75 percent of its gross revenues from provision of electric 23.7 service, excluding gross operating revenues from electric 23.8 service provided in the state to large electric customer 23.9 facilities for which the commissioner of public service has23.10 issuedan exemption is in effect under subdivision 1a, paragraph 23.11 (b), and 0.6 percent of its gross revenues from provision of gas 23.12 service, excluding gross operating revenues from gas services 23.13 provided in the state to large electric customer facilities for 23.14 which the commissioner of public service has issuedan exemption 23.15 is in effect under subdivision 1a, paragraph (b), for that year 23.16 for energy conservation improvements under this section. 23.17 Sec. 7. [216B.2411] [ENERGY CONSERVATION FOR RELIABLE 23.18 ENERGY SUPPLY.] 23.19 Subdivision 1. [ENERGY CONSERVATION PLAN AND PROGRAM.] The 23.20 commissioner of the department shall, as part of the energy plan 23.21 required under chapter 216E, determine the potential for energy 23.22 conservation improvements as defined in section 216B.241 and 23.23 establish goals for energy conservation. The commissioner may 23.24 propose program strategies, screening and selection procedures, 23.25 budgets, and savings targets for the acquisition of energy 23.26 conservation resources as part of the plan. 23.27 Subd. 2. [ENERGY CONSERVATION UTILITIES.] (a) The 23.28 commission shall certify one or more private entities to design 23.29 and implement energy conservation improvements in the state. 23.30 Certification may authorize operation statewide or may specify 23.31 geographic areas for operation and is for a period of no more 23.32 than five years, must contain terms and conditions consistent 23.33 with this chapter and chapters 216, 216A, 216C, and 216E as 23.34 recommended by the department and approved by the commission. 23.35 Certification renewal is subject to the same conditions as the 23.36 initial certification. The commission may terminate a 24.1 certification for cause based on an evidentiary record and a 24.2 hearing and findings on the record. The owners, directors, and 24.3 staff of an energy conservation utility must be independent of 24.4 any economic or structural affiliation with any entity that 24.5 provides electricity, natural gas, or petroleum products to 24.6 consumers in Minnesota. An entity that applies for 24.7 certification, at a minimum, shall demonstrate knowledge about 24.8 and experience with effective energy conservation programs, 24.9 modern energy technologies, and marketing strategies. 24.10 (b) The commission shall prescribe by order the duties, 24.11 standards, and procedures related to the operations of energy 24.12 conservation utilities, as well as the procedures and criteria 24.13 for selecting and certifying the utilities. The department, 24.14 under the commission's order, shall conduct a competitive 24.15 application process and shall recommend to the commission 24.16 selection and certification of one or more entities or the 24.17 rejection of all applicants and a new selection process. 24.18 (c) A certified energy conservation utility shall, in close 24.19 coordination with the department, design and implement energy 24.20 conservation programs. All programs must be designed and 24.21 implemented to efficiently and effectively provide energy 24.22 conservation services to all energy consumers on a 24.23 nondiscriminatory and cost-effective basis. 24.24 (d) A conservation utility may provide energy conservation 24.25 services directly or under contracts with others and may solicit 24.26 and review bids to implement conservation programs or projects 24.27 from any entity, including private entities, local government 24.28 units, community organizations, public utilities, municipal 24.29 utilities, and cooperative electric associations, and may award 24.30 contracts to successful bidders. The utility may seek and the 24.31 department may grant approval to negotiate contracts for 24.32 conservation services, without competitive bids, for innovative 24.33 services, for services provided by proven companies who provide 24.34 documentation of real energy savings resulting from their 24.35 proposed programs, or other services when competitive bidding 24.36 would serve little or no purpose. Selection of energy 25.1 conservation contractors, by bid or negotiation, must be based 25.2 on the quality, reliability, cost effectiveness, replicability, 25.3 and sustainability of proposed conservation services. To the 25.4 greatest extent possible, each energy conservation utility shall 25.5 coordinate its activities with all the other conservation 25.6 utilities and the department to ensure that the same level of 25.7 conservation services are to all similarly situated consumers 25.8 regardless of geographic location in the state and to ensure 25.9 that the activities of the conservation utilities and their 25.10 contractors are consistent with and are designed to meet the 25.11 goals of the state energy plan approved by the commission under 25.12 section 216E.06. 25.13 (e) An energy conservation utility shall report annually on 25.14 or before its certification anniversary to the commission and 25.15 the department. The report must summarize the utility's 25.16 activities, energy savings resulting from those activities, its 25.17 business and operation plan for the next two-year period, and 25.18 expected energy savings over that time period. The conservation 25.19 utility shall include in its report the results of an 25.20 independent audit performed by a certified public accountant and 25.21 shall make its books and records available for inspection by the 25.22 department and commission. The commissioner or the commission 25.23 may order a conservation utility to include a specific program 25.24 or project in the utility's operation plan at any time and shall 25.25 ensure that all energy conservation utilities provide 25.26 conservation services needed in common by all consumers in the 25.27 state. 25.28 (f) The department shall assist energy conservation 25.29 utilities with the design of energy conservation programs and 25.30 projects and shall monitor and evaluate program and project 25.31 implementation and effectiveness and make recommendations to the 25.32 commission on certification, recertification, or decertification 25.33 of conservation utilities. 25.34 Subd. 3. [TRANSITION TIME PERIOD AND FUNDING.] (a) An 25.35 energy conservation utility shall bill each public utility, 25.36 municipal utility, or cooperative electric association subject 26.1 to section 216B.241 for that utility's or association's share of 26.2 the programs and administrative costs of the energy conservation 26.3 utility. The commission shall determine the maximum amount an 26.4 energy conservation utility may bill and each public utility's, 26.5 municipal utility's, or cooperative electric association's 26.6 prorated share of each energy conservation utility's costs based 26.7 on the relative gross operating revenues of each entity and the 26.8 geographic area in which the conservation utility is certified 26.9 to operate. 26.10 (b) The total amount all certified energy conservation 26.11 utilities may bill to public utilities, municipal utilities, and 26.12 cooperative electric associations that are subject to section 26.13 216B.241 may not exceed: 26.14 (1) $10,000,000 in fiscal year 2002; 26.15 (2) $20,000,000 in fiscal year 2003; 26.16 (3) $50,000,000 in fiscal year 2004; and 26.17 (4) an amount to be determined by the commission, but not 26.18 less than $75,000,000 in fiscal year 2005 and thereafter. 26.19 (c) Amounts billed are payable within 30 days of receipt, 26.20 may be used to meet energy conservation improvement obligations 26.21 under section 216B.241, and are recoverable as provided in 26.22 section 216B.241 when they are used to meet the obligations 26.23 under that section. 26.24 (d) An energy conservation utility, to the maximum extent 26.25 possible, shall use conservation dollars to benefit energy 26.26 consumers in the geographic area of the state from which the 26.27 dollars came. 26.28 Subd. 4. [REQUIREMENTS; OPTIONS.] (a) An energy 26.29 conservation utility shall coordinate programs with the 26.30 weatherization assistance program, community-based energy 26.31 conservation programs, local government units, community 26.32 organizations, and the department to deliver conservation 26.33 services to households in the state whose income is less than 26.34 185 percent of the federal poverty level. 26.35 (b) A conservation utility may invest in research and 26.36 development projects and programs related to energy conservation 27.1 and development of modern energy technology that reduces the 27.2 need for new traditional energy resources but not more than 25 27.3 percent of a conservation utility's total budget may be used for 27.4 these purposes. 27.5 (c) When a public utility, municipal utility, or 27.6 cooperative electric association contracts with an energy 27.7 conservation utility, the dollar amount to execute the contract 27.8 may be credited against the obligation of the public utility, 27.9 municipal utility, or cooperative utility under subdivision 3 27.10 and section 216B.241 and need not be actually transferred 27.11 between the entities, unless the contract is not performed or is 27.12 not performed according to the specifications in the contract. 27.13 (d) A public utility, municipal utility, or cooperative 27.14 electric association subject to section 216B.241 may opt to 27.15 transfer more than its transitional share of conservation funds 27.16 under subdivision 3 in fiscal year 2002, 2003, or 2004. If an 27.17 entity chooses this option, it must notify the commission by 27.18 September 1, 2001, for fiscal year 2002; by April 1, 2002, for 27.19 fiscal year 2003; or by April 1, 2003, for fiscal year 2004. An 27.20 entity may opt to transfer all of its required conservation 27.21 improvement spending dollars required under section 216B.241 or 27.22 otherwise by the commission at any time prior to fiscal year 27.23 2005, and the only applicability of section 216B.241 is to 27.24 govern spending or investment of any amount utilities and 27.25 associations are required to spend under that section over the 27.26 amount required to be available for conservation utilities under 27.27 subdivision 3 and govern recovery by public utilities of amounts 27.28 spent for energy conservation through energy conservation 27.29 utilities. 27.30 Sec. 8. [REPEALER.] 27.31 Minnesota Statutes 2000, section 216B.241, subdivision 2a, 27.32 is repealed. 27.33 ARTICLE 3 27.34 MODERN ENERGY TECHNOLOGIES 27.35 Section 1. Minnesota Statutes 2000, section 116C.691, 27.36 subdivision 2, is amended to read: 28.1 Subd. 2. [LARGE WIND ENERGY CONVERSION SYSTEM OR LWECS.] 28.2 "Large wind energy conversion system" or "LWECS" means any 28.3 combination of WECSwind energy conversion systems (WECS) with a 28.4 combined nameplate capacity of 5,000 kilowatts ormore than 30 28.5 megawatts. 28.6 Sec. 2. Minnesota Statutes 2000, section 116C.691, is 28.7 amended by adding a subdivision to read: 28.8 Subd. 2a. [MEDIUM WIND ENERGY CONVERSION SYSTEMS OR 28.9 MWECS.] "Medium wind energy conversion system" or "MWECS" means 28.10 any combination of wind energy conversion systems (WECS) with a 28.11 nameplate capacity of five through 30 megawatts. 28.12 Sec. 3. Minnesota Statutes 2000, section 116C.692, is 28.13 amended to read: 28.14 116C.692 [EXEMPTIONS.] 28.15 (a) The requirements of sections 116C.51 to 116C.69 do not 28.16 apply to the siting of LWECS, except for sections 116C.52; 28.17 116C.57, subdivision 4; 116C.59; 116C.62; 116C.63; 116C.645; 28.18 116C.65; 116C.68; and 116C.69, subdivision 3, which do apply. 28.19 (b) Siting of MWECS is subject to sections 216E.04 and 28.20 216E.12 and not to the requirements of sections 116C.51 to 28.21 116C.697. 28.22 (c) Any person may construct an SWECS without complying 28.23 with sections 116C.51 to 116C.69 and 116C.691 to 116C.697. 28.24 (c)(d) Nothing in sections 116C.691 to 116C.697 shall 28.25 preclude a local governmental unit from establishing 28.26 requirements for the siting and construction of SWECS. 28.27 Sec. 4. Minnesota Statutes 2000, section 116C.779, is 28.28 amended to read: 28.29 116C.779 [FUNDING FOR RENEWABLE DEVELOPMENT.] 28.30 Subdivision 1. [RENEWABLE DEVELOPMENT FUNDACCOUNT.] (a)28.31 The public utility that operates the Prairie Island nuclear 28.32 generating plant must transfer to aan interest-bearing 28.33 renewable development account $500,000 each year for each dry 28.34 cask containing spent fuel that is located at the independent 28.35 spent fuel storage installation at Prairie Island after January 28.36 1, 1999. Earnings, such as interest, dividends, and any other 29.1 earnings from fund assets, must be credited to the account. The 29.2 fund transfer must be made if waste is stored in a cask for any 29.3 part of a year. Funds in the account may be expended only for 29.4 development of renewable energy sources. Preference must be 29.5 given to development of renewable energy source projects located 29.6 within the state. 29.7 (b)Subd. 2. [COMMISSION APPROVAL FOR EXPENDITURES.] 29.8 Expenditures from the account may only be made after approval by 29.9 order of the public utilities commission upon a petition by the 29.10 public utility. 29.11 Sec. 5. Minnesota Statutes 2000, section 216B.164, 29.12 subdivision 3, is amended to read: 29.13 Subd. 3. [PURCHASES; SMALL FACILITIES.] (a) For a 29.14 qualifying facility having two megawatts or less than29.15 40-kilowattnameplate capacity, the customer shallmust be 29.16 billed for the net energy supplied by the utility according to 29.17 the applicable rate schedule for sales to that class of customer. 29.18 (b) In the case of net input into the utility system by a 29.19 qualifying facility having less than 40-kilowatt nameplate 29.20 capacity, compensation to the customer shallmust be at a per29.21 kilowatt hour rate determined under paragraph (b) or (c) of this29.22 subdivision.29.23 (b) In setting rates, the commission shall consider the29.24 fixed distribution costs to the utility not otherwise accounted29.25 for in the basic monthly charge and shall ensure that the costs29.26 charged to the qualifying facility are not discriminatory in29.27 relation to the costs charged to other customers of the utility.29.28 The commission shall set the rates for net input into the29.29 utility system based on avoided costs as defined in the Code of29.30 Federal Regulations, title 18, section 292.101(b)(6), the29.31 factors listed in Code of Federal Regulations, title 18, section29.32 292.304, and all other relevant factors.29.33 (c) Notwithstanding any provision in this chapter to the29.34 contrary, a qualifying facility having less than 40-kilowatt29.35 capacity may elect that the compensation for net input by the29.36 qualifying facility into the utility system shall be atthe 30.1 average retail utility energy rate. "Average retail utility 30.2 energy rate" is defined as the average of the retail energy 30.3 rates, exclusive of special rates based on income, age, or 30.4 energy conservation, according to the applicable rate schedule 30.5 of the utility for sales to that class of customer. 30.6 (c) Notwithstanding subdivision 4, for a qualifying 30.7 facility of 40-kilowatt capacity through two megawatts of 30.8 nameplate capacity, the compensation for net input by the 30.9 qualifying facility into the utility system is the market price 30.10 for energy at the time the facility began putting energy into 30.11 the utility system and must be adjusted to the present market 30.12 price at least once every three years. For the purposes of this 30.13 paragraph, "market price" means the average price paid by all 30.14 utilities in Minnesota for energy from facilities that utilize 30.15 the same energy source as the qualifying facility. 30.16 (d) If the qualifying facility is interconnected with a 30.17 nongenerating utility whichthat has a sole source contract with 30.18 a municipal power agency or a generation and transmission 30.19 utility, the nongenerating utility may elect to treat its 30.20 purchase of any net input under this subdivision as being made 30.21 on behalf of its supplier and shallmust be reimbursed by its 30.22 supplier for any additional costs incurred in making the 30.23 purchase. Qualifying facilities having less than 40-kilowatt 30.24 capacity may, at the customer's option, elect to be governed by 30.25 the provisions of subdivision 4. 30.26 Sec. 6. Minnesota Statutes 2000, section 216B.164, 30.27 subdivision 6, is amended to read: 30.28 Subd. 6. [RULES AND UNIFORM CONTRACT.] (a) The commission 30.29 shall promulgate rules to implement the provisions of this 30.30 section. The commission shall also establish a uniform 30.31 statewide form of contract for use between utilities and a 30.32 qualifying facility having a capacity of two megawatts or less 30.33 than 40-kilowatt capacity. 30.34 (b) The commission shall require the qualifying facility to 30.35 provide the utility with reasonable access to the premises and 30.36 equipment of the qualifying facility if the particular 31.1 configuration of the qualifying facility precludes disconnection 31.2 or testing of the qualifying facility from the utility side of 31.3 the interconnection with the utility remaining responsible for 31.4 its personnel. 31.5 (c) The uniform statewide form of contract shallmust be 31.6 applied to all new and existing interconnections established 31.7 between a utility and a qualifying facility having less than 31.8 40-kilowatt capacity, except that existing contracts may remain 31.9 in force until written notice of election that the uniform 31.10 statewide contract form applies is given by either party to the 31.11 other, with the notice being of the shortest time period 31.12 permitted under the existing contract for termination of the 31.13 existing contract by either party, but not less than ten nor 31.14 longer than 30 days. 31.15 Sec. 7. [216B.68] [DEFINITIONS.] 31.16 Subdivision 1. [SCOPE.] The words and terms used in 31.17 sections 216B.68 to 216B.75 have the meanings given them in this 31.18 section. 31.19 Subd. 2. [APPLICATION FOR INTERCONNECTION AND PARALLEL 31.20 OPERATION.] "Application for interconnection and parallel 31.21 operation with the utility system or application" means a 31.22 standard form of application developed by the commissioner and 31.23 approved by the commission. 31.24 Subd. 3. [COMPANY.] "Company" means an electric utility 31.25 operating a distribution system. 31.26 Subd. 4. [ELECTRIC UTILITY.] "Electric utility" means all 31.27 electric utilities that own and operate equipment in the state 31.28 for furnishing electric service at retail. 31.29 Subd. 5. [CUSTOMER.] "Customer" means any individual 31.30 person or entity interconnected to the company's utility system 31.31 for the purpose of receiving or exporting electric power from or 31.32 to the company's utility system. 31.33 Subd. 6. [DISTRIBUTED GENERATION OR ON-SITE DISTRIBUTED 31.34 GENERATION.] "Distributed generation" or "on-site distributed 31.35 generation" means an electrical generating facility located at a 31.36 customer's point of delivery or point of common coupling of ten 32.1 megawatts or less and connected at a voltage less than or equal 32.2 to 60 kilovolts that may be connected in parallel operation to 32.3 the utility system. 32.4 Subd. 7. [FACILITY.] "Facility" means an electrical 32.5 generating installation consisting of one or more on-site 32.6 distributed generation units. The total capacity of a 32.7 facility's individual on-site distributed generation units may 32.8 exceed ten megawatts; however, no more than ten megawatts of a 32.9 facility's capacity will be interconnected at any point in time 32.10 at the point of common coupling under this section. 32.11 Subd. 8. [INTERCONNECTION.] "Interconnection" means the 32.12 physical connection of distributed generation to the utility 32.13 system in accordance with the requirements of this section so 32.14 that parallel operation can occur. 32.15 Subd. 9. [INTERCONNECTION AGREEMENT.] "Interconnection 32.16 agreement" means the standard form of agreement, developed and 32.17 approved by the commission. The interconnection agreement sets 32.18 forth the contractual conditions under which a company and a 32.19 customer agree that one or more facilities may be interconnected 32.20 with the company's utility system. 32.21 Subd. 10. [INVERTER-BASED PROTECTIVE 32.22 FUNCTION.] "Inverter-based protective function" means a function 32.23 of an inverter system, carried out using hardware and software, 32.24 that is designed to prevent unsafe operating conditions from 32.25 occurring before, during, and after the interconnection of an 32.26 inverter-based static power converter unit with a utility 32.27 system. For purposes of this definition, unsafe operating 32.28 conditions are conditions that, if left uncorrected, would 32.29 result in harm to personnel, damage to equipment, unacceptable 32.30 system instability, or operation outside legally established 32.31 parameters affecting the quality of service to other customers 32.32 connected to the utility system. 32.33 Subd. 11. [NETWORK SERVICE.] "Network service" means two 32.34 or more utility primary distribution feeder sources electrically 32.35 tied together on the secondary side, which is the low-voltage 32.36 side, to form one power source for one or more customers. The 33.1 service is designed to maintain service to the customers even 33.2 after the loss of one of these primary distribution feeder 33.3 sources. 33.4 Subd. 12. [PARALLEL OPERATION.] "Parallel operation" means 33.5 the operation of on-site distributed generation by a customer 33.6 while the customer is connected to the company's utility system. 33.7 Subd. 13. [POINT OF COMMON COUPLING.] "Point of common 33.8 coupling" means the point where the electrical conductors of the 33.9 company utility system are connected to the customer's 33.10 conductors and where any transfer of electric power between the 33.11 customer and the utility system takes place, such as switchgear 33.12 near the meter. 33.13 Subd. 14. [PRECERTIFIED EQUIPMENT.] "Precertified 33.14 equipment" means a specific generating and protective equipment 33.15 system or systems that have been certified as meeting the 33.16 applicable parts of this section relating to safety and 33.17 reliability by an entity approved by the commission. 33.18 Subd. 15. [PRE-INTERCONNECTION STUDY.] 33.19 "Pre-interconnection study" means a study or studies that may be 33.20 undertaken by a company in response to its receipt of a 33.21 completed application for interconnection and parallel operation 33.22 with the utility system. Pre-interconnection studies may 33.23 include, but are not limited to, service studies, coordination 33.24 studies, and utility system impact studies. 33.25 Subd. 16. [STABILIZED.] "Stabilized" means that, following 33.26 a disturbance, a company utility system has returned to the 33.27 normal range of voltage and frequency for a duration of two 33.28 minutes or a shorter time as mutually agreed to by the company 33.29 and customer. 33.30 Subd. 17. [TARIFF OR TARIFF FOR INTERCONNECTION AND 33.31 PARALLEL OPERATION OF DISTRIBUTED GENERATION.] "Tariff" or 33.32 "Tariff for interconnection and parallel operation of 33.33 distributed generation" means the commission-developed and 33.34 commission-approved tariff for interconnection and parallel 33.35 operation of distributed generation, including the application 33.36 for interconnection and parallel operation of distributed 34.1 generation and pre-interconnection study fee schedule. 34.2 Subd. 18. [UNIT.] "Unit" means a power generator. 34.3 Subd. 19. [UTILITY SYSTEM.] "Utility system" means a 34.4 company's distribution system below 60 kilovolts to which the 34.5 generation equipment is interconnected. 34.6 Sec. 8. [216B.69] [INTERCONNECTION OF ON-SITE DISTRIBUTED 34.7 GENERATION.] 34.8 Subdivision 1. [PURPOSE.] The purpose of sections 216B.68 34.9 to 216B.75 is to state the terms and conditions that govern the 34.10 interconnection and parallel operation of on-site distributed 34.11 generation to provide cost savings and reliability benefits to 34.12 customers, to establish technical requirements that will promote 34.13 the safe and reliable parallel operation of on-site distributed 34.14 generation resources, to enhance both the reliability of 34.15 electric service and economic efficiency in the production and 34.16 consumption of electricity, and to promote the use of 34.17 distributed resources in order to provide electric system 34.18 benefits during periods of capacity constraints. 34.19 Subd. 2. [OBLIGATION TO SERVE; TARIFF AND OTHER 34.20 FILINGS.] (a) No later than 270 days after the effective date of 34.21 this section, each electric utility shall file tariffs for 34.22 interconnection and parallel operation of distributed generation 34.23 in conformance with sections 216B.68 to 216B.75. The electric 34.24 utility may file a new tariff or a modification of an existing 34.25 tariff. These tariffs must ensure that backup power, 34.26 supplemental power, and maintenance power are available to all 34.27 customers and customer classes that desire this service. Any 34.28 modifications of existing tariffs or offerings of new tariffs 34.29 relating to this section must be consistent with the 34.30 commission-approved form. 34.31 (b) Concurrent with the tariff filing in this section, each 34.32 utility shall submit: 34.33 (1) a schedule detailing the charges of interconnection 34.34 studies and all supporting cost data for the charges; 34.35 (2) a standard application for interconnection and parallel 34.36 operation of distributed generation; and 35.1 (3) the interconnection agreement approved by the 35.2 commission. 35.3 Sec. 9. [216B.70] [DISCONNECTION AND RECONNECTION.] 35.4 Subdivision 1. [WHEN DISCONNECTION ALLOWED.] A utility may 35.5 disconnect a distributed generation unit from the utility system 35.6 if: 35.7 (1) the interconnection agreement with a customer expires 35.8 or terminates, in accordance with the terms of the agreement; 35.9 (2) the facility is not in compliance with the technical 35.10 requirements specified by the commissioner; 35.11 (3) continued interconnection will endanger persons or 35.12 property; or 35.13 (4) written notice is provided at least seven business days 35.14 prior to a service interruption for routine maintenance, 35.15 repairs, and utility system modifications. 35.16 Subd. 2. [INCREMENTAL DEMAND CHARGES.] During the term of 35.17 an interconnection agreement, a utility may require that a 35.18 customer disconnect its distributed generation unit or take it 35.19 off-line as a result of utility system conditions. The company 35.20 may not assess the customer incremental demand charges arising 35.21 from disconnecting the distributed generator as directed by the 35.22 company during these periods. 35.23 Sec. 10. [216B.71] [PRE-INTERCONNECTION STUDIES FOR 35.24 NONNETWORK INTERCONNECTION OF DISTRIBUTED GENERATION.] 35.25 Subdivision 1. [STUDIES.] A utility may conduct a service 35.26 study, coordination study, or utility system impact study prior 35.27 to interconnection of a distributed generation facility. When a 35.28 study is deemed necessary, the scope of the study must be based 35.29 on the characteristics of the particular distributed generation 35.30 facility to be interconnected and the utility's system at the 35.31 specific proposed location. By agreement between the utility 35.32 and its customer, a study related to interconnection of 35.33 distributed generation on the customer's premises may be 35.34 conducted by a qualified third party. 35.35 Subd. 2. [CUSTOMER FEE.] (a) A utility may not charge a 35.36 customer a fee to conduct a pre-interconnection study for 36.1 precertified distributed generation units up to 500 kilowatts 36.2 that export not more than 15 percent of the total load on a 36.3 single radial feeder and contribute not more than 25 percent of 36.4 the maximum potential short circuit current on a single radial 36.5 feeder. 36.6 (b) Prior to the interconnection of a distributed 36.7 generation facility not described in paragraph (a), a utility 36.8 may charge a customer a fee to offset its costs incurred in the 36.9 conduct of a pre-interconnection study. 36.10 Subd. 3. [WHEN UTILITY CONDUCTS STUDY.] When a utility 36.11 conducts an interconnection study, paragraphs (a) to (d) apply: 36.12 (a) The conduct of the pre-interconnection study may not 36.13 take more than four weeks. 36.14 (b) A utility shall prepare written reports of the study 36.15 findings and make them available to the customer. 36.16 (c) The study must consider both the costs incurred and the 36.17 benefits realized as a result of the interconnection of 36.18 distributed generation to the company's utility system. 36.19 (d) The utility shall provide the customer with an estimate 36.20 of the study cost before the utility initiates the study. 36.21 Sec. 11. [216B.72] [PRE-INTERCONNECTION STUDIES FOR 36.22 NETWORK INTERCONNECTION OF DISTRIBUTED GENERATION.] 36.23 Subdivision 1. [NOTICE AND FEES.] (a) Prior to charging a 36.24 pre-interconnection study fee for a network interconnection of 36.25 distributed generation, a utility shall first advise the 36.26 customer of the potential problems associated with 36.27 interconnection of distributed generation with its network 36.28 system. 36.29 (b) For potential interconnections to network systems, a 36.30 pre-interconnection study fee may not be assessed for a facility 36.31 with inverter systems under 20 kilowatts. For all other 36.32 facilities, the utility may charge the customer a fee to offset 36.33 its costs incurred in the conduct of the pre-interconnection 36.34 study. 36.35 Subd. 2. [REQUIREMENTS WHEN UTILITY CONDUCTS STUDY.] When 36.36 a utility conducts an interconnection study, paragraphs (a) to 37.1 (d) apply: 37.2 (a) The conduct of a pre-interconnection study may not take 37.3 more than four weeks. 37.4 (b) A utility shall prepare written reports of the study 37.5 findings and make them available to the customer. 37.6 (c) The study must consider both the costs incurred and the 37.7 benefits realized as a result of the interconnection of 37.8 distributed generation to the utility's system. 37.9 (d) The utility shall provide the customer with an estimate 37.10 of the study cost before the utility initiates the study. 37.11 Sec. 12. [216B.73] [EQUIPMENT PRECERTIFICATION.] (a) The 37.12 commission may approve one or more entities that shall 37.13 precertify equipment as described under this section. 37.14 (b) Testing organizations or facilities capable of 37.15 analyzing the function, control, and protective systems of 37.16 distributed generation units may request to be certified as 37.17 testing organizations. 37.18 (c) Distributed generation units that are certified to be 37.19 in compliance by an approved testing facility or organization 37.20 must be installed on a company utility system in accordance with 37.21 an approved interconnection control and protection scheme 37.22 without further review of their design by the utility. 37.23 Sec. 13. [216B.74] [TIME FOR PROCESSING APPLICATIONS FOR 37.24 INTERCONNECTION.] 37.25 (a) The interconnection of distributed generation to the 37.26 utility system must take place within the schedules described in 37.27 paragraphs (b) to (f): 37.28 (b) For a facility with precertified equipment, 37.29 interconnection must take place within four weeks of the 37.30 utility's receipt of a completed interconnection application. 37.31 (c) For facilities without precertified equipment, 37.32 connection must take place within six weeks of the utility's 37.33 receipt of a completed application. 37.34 (d) If interconnection of a particular facility will 37.35 require substantial capital upgrades to the utility system, the 37.36 company shall provide the customer an estimate of the schedule 38.1 and the customer's cost for the upgrade. If the customer 38.2 desires to proceed with the upgrade, the customer and the 38.3 company shall enter into a contract for the completion of the 38.4 upgrade. The interconnection must take place no later than two 38.5 weeks following the completion of the upgrade. The utility 38.6 shall employ best reasonable efforts to complete the system 38.7 upgrade in the shortest time reasonably practical. 38.8 (e) A utility shall use best reasonable efforts to 38.9 interconnect facilities within the time frames described in this 38.10 section. If in a particular instance, a utility determines that 38.11 it cannot interconnect a facility within the time frames stated 38.12 in this section, it must notify the applicant in writing of that 38.13 fact. The notification must identify any reasons 38.14 interconnection could not be performed in accordance with the 38.15 schedule and provide an estimated date for interconnection. 38.16 (f) Applications for interconnection and parallel operation 38.17 of distributed generation must be processed by the utility in a 38.18 nondiscriminatory manner and in the order that they are 38.19 received. It is recognized that certain applications may 38.20 require minor modifications while they are being reviewed by the 38.21 utility. These minor modifications to a pending application do 38.22 not require that it be considered incomplete and treated as a 38.23 new or separate application. 38.24 Sec. 14. [216B.75] [REPORTING REQUIREMENTS.] 38.25 (a) Each electric utility shall maintain records concerning 38.26 applications received for interconnection and parallel operation 38.27 of distributed generation. The records must include the date 38.28 each application is received, documents generated in the course 38.29 of processing each application, correspondence regarding each 38.30 application, and the final disposition of each application. 38.31 (b) By March 30 of each year, every electric utility shall 38.32 file with the commission a distributed generation 38.33 interconnection report for the preceding calendar year that 38.34 identifies each distributed generation facility interconnected 38.35 with the utility's distribution system. The report must list 38.36 the new distributed generation facilities interconnected with 39.1 the system since the previous year's report, any distributed 39.2 generation facilities no longer interconnected with the 39.3 utility's system since the previous report, the capacity of each 39.4 facility, and the feeder or other point on the company's utility 39.5 system where the facility is connected. The annual report must 39.6 also identify all applications for interconnection received 39.7 during the previous one-year period, and the disposition of the 39.8 applications. 39.9 Sec. 15. Minnesota Statutes 2000, section 216C.41, 39.10 subdivision 1, is amended to read: 39.11 Subdivision 1. [DEFINITIONS.] (a) The definitions in this 39.12 subdivision apply to this section. 39.13 (b) "Qualified hydroelectric facility" means a 39.14 hydroelectric generating facility in this state that: 39.15 (1) is located at the site of a dam, if the dam was in 39.16 existence as of March 31, 1994; and 39.17 (2) either begins generating electricity after July 1, 39.18 1994, or resumes generating electricity after substantial 39.19 refurbishing of the facility that begins after July 1, 2001. 39.20 (c) "Qualified wind energy conversion facility" means a 39.21 wind energy conversion system that: 39.22 (1) produces two megawatts or less of electricity as 39.23 measured by nameplate rating and begins generating electricity 39.24 after June 30, 1997, and before July 1, 1999; 39.25 (2) begins generating electricity after June 30, 1999, 39.26 produces two megawatts or less of electricity as measured by 39.27 nameplate rating, and is: 39.28 (i) located within one county and owned by a natural person 39.29 who owns the land where the facility is sited; 39.30 (ii) owned by a Minnesota small business as defined in 39.31 section 645.445; 39.32 (iii) owned by a nonprofit organization; or39.33 (iv) owned by a tribal council if the facility is located 39.34 within the boundaries of the reservation; or 39.35 (v) owned by a municipal utility or a cooperative electric 39.36 association; 40.1 (3) begins generating electricity after June 30, 1999, 40.2 produces seven megawatts or less of electricity as measured by 40.3 nameplate rating, and: 40.4 (i) is owned by a cooperative organized under chapter 308A; 40.5 and 40.6 (ii) all shares and membership in the cooperative are held 40.7 by natural persons or estates, at least 51 percent of whom 40.8 reside in a county or contiguous to a county where the wind 40.9 energy production facilities of the cooperative are located .; or 40.10 (4) begins generating electricity after June 30, 2001, 40.11 produces 20 megawatts or less of electricity as measured by 40.12 nameplate rating, is not, in whole or in part, used to meet the 40.13 wind power mandate in section 216B.2423, and is not located in 40.14 the counties of Lincoln, Lyon, Murray, Nobles, Pipestone, or 40.15 Rock. 40.16 (d) "Qualified solar energy conversion facility" means a 40.17 solar energy conversion system that is located in this state, 40.18 that is not owned by a public utility or a subsidiary or 40.19 affiliate of a public utility, and that produces ten or less 40.20 kilowatts of electricity as measured by nameplate rating. 40.21 Sec. 16. Minnesota Statutes 2000, section 216C.41, 40.22 subdivision 3, is amended to read: 40.23 Subd. 3. [ELIGIBILITY WINDOW.] Payments may be made under 40.24 this section only for electricity generated: 40.25 (1) from a qualified hydroelectric facility that is 40.26 operational and generating electricity before December 31, 40.27 20012005; or40.28 (2) from a qualified wind energy conversion facility that 40.29 is operational and generating electricity before January 1, 200540.30 2007; or 40.31 (3) from a qualified solar energy conversion facility that 40.32 is operational and generating electricity before January 1, 2010. 40.33 Sec. 17. Minnesota Statutes 2000, section 216C.41, 40.34 subdivision 4, is amended to read: 40.35 Subd. 4. [PAYMENT PERIOD.] (a) A facility may receive 40.36 payments under this section for a ten-year period. No payment 41.1 under this section may be made for electricity generated: 41.2 (1) by a qualified hydroelectric facility after December 41.3 31, 2010; or2015; 41.4 (2) by a qualified wind energy conversion facility after 41.5 December 31, 20152017; or 41.6 (3) by a qualified solar energy conversion facility after 41.7 December 31, 2020. 41.8 (b) The payment period begins and runs consecutively from 41.9 the first year in which electricity generated from the facility 41.10 is eligible for incentive payment. 41.11 Sec. 18. Minnesota Statutes 2000, section 216C.41, 41.12 subdivision 5, is amended to read: 41.13 Subd. 5. [AMOUNT OF PAYMENT.] (a) An incentive payment is 41.14 based on the number of kilowatt hours of electricity generated. 41.15 The amount of the payment is: 41.16 (1) 1.5 cents per kilowatt hour .of electricity generated 41.17 by a qualified hydroelectric facility or a qualified wind 41.18 conversion energy facility as defined in subdivision 1, 41.19 paragraph (c), clause (1), (2), or (3); 41.20 (2) one cent per kilowatt hour of electricity generated by 41.21 a qualified wind energy conversion facility as defined in 41.22 subdivision 1, paragraph (c), clause (4); and 41.23 (3) ten cents per kilowatt hour of electricity generated by 41.24 a qualified solar energy conversion facility. 41.25 (b) For electricity generated by qualified wind energy 41.26 conversion facilities, the incentive payment under this section 41.27 is limited to no more than 100300 megawatts of nameplate 41.28 capacity. During any period in which qualifying claims for 41.29 incentive payments exceed 100300 megawatts of nameplate 41.30 capacity, the payments must be made to producers in the order in 41.31 which the production capacity was brought into production. 41.32 (c) Beginning January 1, 2002, a qualified wind energy 41.33 conversion facility defined under subdivision 1, paragraph (c), 41.34 clause (1), (2), or (3), may not be located within five miles of 41.35 another qualified wind energy conversion facility constructed 41.36 within the same calendar year and owned by the same person. For 42.1 the purposes of this paragraph, the department shall determine 42.2 that the same person owns two qualified wind energy conversion 42.3 facilities when the underlying ownership structure contains 42.4 similar persons or entities, other than a person or entity that 42.5 provides equity financing, even if the ownership shares differ 42.6 between the facilities. 42.7 (d) Not more than 150 megawatts of nameplate capacity may 42.8 receive incentive payments for qualified facilities as defined 42.9 in subdivision 1, paragraph (c), clause (4). Nothing in this 42.10 section reserves any number of megawatts for facilities that 42.11 qualify under subdivision 1, paragraph (c), clause (4). 42.12 (e) Notwithstanding subdivision 2, for a qualified wind 42.13 energy conversion facility with a nameplate rating of 100 42.14 kilowatts or less in operation on July 1, 2001, or thereafter, 42.15 and for a qualified solar energy conversion facility that is in 42.16 operation on July 1, 2001, or thereafter, regardless of 42.17 installation date, the incentive payment is based on the total 42.18 amount of electricity generated by the facility, whether it is 42.19 used on-site or otherwise or sold to another entity. For 42.20 qualified solar energy conversion facilities, the incentive 42.21 payment under this section is limited to 25 megawatts of 42.22 nameplate capacity. 42.23 (f) Notwithstanding subdivision 2, incentive payments may 42.24 be made only to the facility owner unless the owner, in writing, 42.25 directs that payment be made to another person or entity. 42.26 Sec. 19. Minnesota Statutes 2000, section 216C.41, is 42.27 amended by adding a subdivision to read: 42.28 Subd. 6. [OWNERSHIP; FINANCING; CURE.] (a) For the 42.29 purposes of subdivision 1, paragraph (c), clause (2), a wind 42.30 energy conversion facility qualifies if it is owned at least 51 42.31 percent by one or more of any combination of the entities listed 42.32 in that clause. 42.33 (b) A subsequent owner of a qualified facility may continue 42.34 to receive the incentive payment for the duration of the 42.35 original payment period if the subsequent owner qualifies for 42.36 the incentive under subdivision 1. 43.1 (c) Nothing in this section may be construed to deny 43.2 incentive payment to an otherwise qualified facility that has 43.3 obtained debt or equity financing for construction or operation 43.4 as long as the ownership requirements of subdivision 1 and this 43.5 subdivision are met. If, during the incentive payment period 43.6 for a qualified facility, the owner of the facility is in 43.7 default of a lending agreement and the lender takes possession 43.8 of and operates the facility and makes reasonable efforts to 43.9 transfer ownership of the facility to an entity other than the 43.10 lender, the lender may continue to receive the incentive payment 43.11 for electricity generated and sold by the facility for a period 43.12 not to exceed 18 months. A lender who takes possession of a 43.13 facility shall notify the commissioner immediately on taking 43.14 possession and, at least quarterly, document efforts to transfer 43.15 ownership of the facility. 43.16 (d) If, during the incentive payment period, a qualified 43.17 facility loses the right to receive the incentive because of 43.18 changes in ownership, the facility may regain the right to 43.19 receive the incentive upon cure of the ownership structure that 43.20 resulted in the loss of eligibility and may reapply for the 43.21 incentive, but in no case may the payment period be extended 43.22 beyond the original ten-year limit. 43.23 (e) A subsequent or requalifying owner under paragraph (b) 43.24 or (d) retains the facility's original priority order for 43.25 incentive payments as long as the ownership structure 43.26 requalifies within two years from the date the facility became 43.27 unqualified or two years from the date a lender takes possession 43.28 of the facility. 43.29 ARTICLE 4 43.30 MISCELLANEOUS PROVISIONS 43.31 Section 1. Minnesota Statutes 2000, section 216A.07, is 43.32 amended by adding a subdivision to read: 43.33 Subd. 7. [GIFTS.] Notwithstanding section 7.09, the 43.34 commissioner may receive and accept, on behalf of the department 43.35 of commerce, any gift, bequest, devise, or endowment made by any 43.36 person by will, deed, gift, or otherwise to or for the benefit, 44.1 support, or maintenance of any educational, charitable, or other 44.2 proper public purpose or function maintained by the department 44.3 of commerce. In order to effect the purpose for which any gift, 44.4 bequest, devise, or endowment has been accepted, the 44.5 commissioner may sell it at a price fixed by the state board of 44.6 investment. Any gift, bequest, devise, or endowment accepted by 44.7 the commissioner under this section is appropriated to the 44.8 commissioner to carry out the terms, conditions, or purposes of 44.9 the gift, bequest, devise, or endowment. 44.10 Sec. 2. [216B.76] [MARKET POWER IN GENERATION.] 44.11 The commission and the department shall jointly monitor the 44.12 structure of the market for electric generation resources, and 44.13 the activities of participants in this market, for the 44.14 appropriate use of market power. The commission shall take all 44.15 necessary steps to protect Minnesota consumers from the 44.16 inappropriate use of market power. 44.17 Sec. 3. [216B.77] [REGIONAL OVERSIGHT.] 44.18 The commissioner shall develop and implement initiatives 44.19 with regulators in other states and regions to develop the 44.20 mechanisms and organizations necessary to ensure that the 44.21 interests of Minnesota consumers are advocated for and protected. 44.22 Sec. 4. [216B.78] [UTILITY RELATIONSHIPS WITH REGIONAL 44.23 INSTITUTIONS.] 44.24 Subdivision 1. [CONTRACT APPROVAL.] No contract or 44.25 arrangement, including any general or continuing arrangement 44.26 between an electric utility and any regional institution seeking 44.27 to have operational control or influence over utility facilities 44.28 in Minnesota, such as an independent system operator or regional 44.29 transmission operator approved by the Federal Energy Regulatory 44.30 Commission, for (1) furnishing management, supervisory, 44.31 construction, engineering, accounting, legal, financial, or 44.32 similar services, (2) purchasing, selling, leasing, or 44.33 exchanging any property, right, or thing, or (3) furnishing any 44.34 service, property, right, or thing, is valid or effective unless 44.35 and until the contract or arrangement has received the written 44.36 approval of the commission. Regular recurring transactions 45.1 under a general or continuing arrangement that has been approved 45.2 by the commission are valid if they are conducted in accordance 45.3 with the approved terms and conditions. Every electric utility 45.4 shall file with the commission a verified copy of the contract 45.5 or arrangement, or a verified summary of the unwritten contract 45.6 or arrangement, and also of all the contracts and arrangements, 45.7 whether written or unwritten. The commission shall approve the 45.8 contract or arrangement made or entered into after that date 45.9 only if it clearly appears and is established upon investigation 45.10 that it is reasonable and consistent with the public interest. 45.11 The burden of proof to establish the reasonableness of the 45.12 contract or arrangement is on the electric utility. 45.13 Subd. 2. [CONTINUING AUTHORITY OF COMMISSION.] The 45.14 commission has continuing supervisory control over the terms and 45.15 conditions of the contracts and arrangements described in 45.16 subdivision 1 necessary to protect and promote the public 45.17 interest. The commission has the same jurisdiction over the 45.18 modifications or amendment of contracts or arrangements as it 45.19 has over original contracts or arrangements. The fact that the 45.20 commission has approved entry into contracts or arrangements 45.21 does not preclude disallowance or disapproval of payments made 45.22 under the contracts or arrangements, if upon actual experience 45.23 the commission determines that the payments provided for or made 45.24 were or are unreasonable. 45.25 Sec. 5. [216B.79] [AUTHORITY TO ORDER FACILITY 45.26 CONSTRUCTION.] 45.27 The commission may order a public utility, municipal 45.28 utility, or rural electric cooperative association to construct 45.29 generation, distribution, or transmission facilities to ensure 45.30 that electric consumers in the state are provided with safe, 45.31 adequate, efficient, and reasonable service. 45.32 Sec. 6. [272.028] [PERSONAL PROPERTY USED TO GENERATE 45.33 ELECTRICITY WHERE CONSTRUCTION STARTED AFTER JANUARY 1, 2001.] 45.34 Personal property used to generate electric power where 45.35 original construction of the generating plant started after 45.36 January 1, 2001, is exempt. This exemption does not apply to 46.1 transformers, transmission lines, distribution lines, or any 46.2 other tools, implements, and machinery that are part of an 46.3 electric substation, wherever located. 46.4 In the case of a plant existing or under construction on 46.5 January 1, 2001, this exemption applies only if the nameplate 46.6 capacity of the plant is increased from that existing on January 46.7 1, 2001. This exemption is computed by taking the increase in 46.8 megawatts over the total megawatt nameplate capacity after 46.9 construction is complete multiplied by the cost of all taxable 46.10 tools, implements, and machinery of the generating plant. 46.11 Sec. 7. [EXPEDITED RULEMAKING.] 46.12 The department or the commission may adopt rules to 46.13 implement this act and may utilize expedited rulemaking where 46.14 necessary to ensure that rules, procedures, standards, or 46.15 criteria are in place in time to ensure reliable short-term and 46.16 long-term energy services. 46.17 ARTICLE 5 46.18 SAFETY AND SERVICE STANDARDS 46.19 Section 1. [216B.80] [DEFINITIONS.] 46.20 Subdivision 1. [SCOPE.] The terms used in this article 46.21 have the meanings given them in this section. 46.22 Subd. 2. [AVERAGE NUMBER OF CUSTOMERS SERVED.] "Average 46.23 number of customers served" means the number of active, metered, 46.24 customer accounts available in a utility's 46.25 interruption-reporting database on the day that an interruption 46.26 occurs. 46.27 Subd. 3. [CIRCUIT.] "Circuit" means a set of conductors 46.28 serving customer loads that are capable of being separated from 46.29 the serving substation automatically by a recloser, fuse, 46.30 sectionalizing equipment, and other devices. 46.31 Subd. 4. [COMPONENT.] "Component" means a piece of 46.32 equipment, a line, a section of line, or a group of items that 46.33 is an entity for purposes of reporting, analyzing, and 46.34 predicting interruptions. 46.35 Subd. 5. [CUSTOMER.] "Customer" means a separately metered 46.36 electrical service point for which a separate bill is rendered, 47.1 i.e., each meter represents a customer. 47.2 Subd. 6. [CUSTOMER INTERRUPTION.] "Customer interruption" 47.3 means the loss of service due to a forced outage for more than 47.4 five minutes, for one or more customers, which is the result of 47.5 one or more component failures. 47.6 Subd. 7. [CUSTOMERS' INTERRUPTIONS CAUSED BY POWER 47.7 RESTORATION PROCESS.] "Customers' interruptions caused by power 47.8 restoration process" means when customers lose power as a result 47.9 of the process of restoring power. The duration of these 47.10 outages is included in the customer-minutes of interruption. 47.11 Only the customers affected by the power restoration outages 47.12 that were not affected by the original outage are added to the 47.13 number of customer interruptions. 47.14 Subd. 8. [CUSTOMER-MINUTES OF 47.15 INTERRUPTION.] "Customer-minutes of interruption" means the 47.16 number of minutes of forced outage duration multiplied by the 47.17 number of customers affected. 47.18 Subd. 9. [ELECTRIC DISTRIBUTION LINE.] "Electric 47.19 distribution line" means circuits operating at less than 40,000 47.20 volts. 47.21 Subd. 10. [FORCED OUTAGE.] "Forced outage" means an outage 47.22 that cannot be deferred. 47.23 Subd. 11. [MAJOR CATASTROPHIC EVENTS.] "Major catastrophic 47.24 events" means events that are beyond the utility's control that 47.25 result in widespread system damages causing customer 47.26 interruptions that affect at least ten percent of the customers 47.27 in the system or in an operating area or that result in 47.28 customers being without electric service for durations of at 47.29 least 24 hours. 47.30 Subd. 12. [MAJOR STORM.] "Major storm" means a period of 47.31 severe adverse weather resulting in widespread system damage 47.32 causing customer interruptions that affect at least ten percent 47.33 of the customers on the system or in an operating area or that 47.34 result in customers being without electric service for durations 47.35 of at least 24 hours. 47.36 Subd. 13. [MOMENTARY INTERRUPTION.] "Momentary 48.1 interruption" means an interruption of electric service with a 48.2 duration shorter than the time necessary to be classified as a 48.3 customer interruption. 48.4 Subd. 14. [OPERATING AREA.] "Operating area" means a 48.5 geographical subdivision of each electric utility's service 48.6 territory that functions under the direction of a company office 48.7 and may be used for reporting interruptions under this article. 48.8 These areas may also be referred to as regions, divisions, or 48.9 districts. 48.10 Subd. 15. [OUTAGE.] "Outage" means the failure of a power 48.11 system component that results in one or more customer 48.12 interruptions. 48.13 Subd. 16. [OUTAGE DURATION.] "Outage duration" means the 48.14 one minute or greater period from the initiation of an 48.15 interruption to a customer until service has been restored to 48.16 that customer. 48.17 Subd. 17. [PARTIAL CIRCUIT OUTAGE CUSTOMER 48.18 COUNT.] "Partial circuit outage customer count" means when only 48.19 part of a circuit experiences an outage, the number of customers 48.20 affected is estimated, unless an actual count is available. 48.21 When power is partially restored, the number of customers 48.22 restored is also estimated. Most utilities use estimates based 48.23 on the portion of the circuit restored. 48.24 Subd. 18. [PLANNED OUTAGES.] "Planned outages" means those 48.25 outages scheduled by the utility. When customer service 48.26 interruptions are necessary, the utility shall notify affected 48.27 customers in advance. These interruptions are sometimes 48.28 necessary to connect new customers or perform maintenance 48.29 activities safely. They must not be included in the calculation 48.30 of reliability indexes. 48.31 Subd. 19. [RELIABILITY.] "Reliability" means the degree to 48.32 which electric service is supplied without interruption. 48.33 Subd. 20. [RELIABILITY INDEXES.] "Reliability indexes" 48.34 include the following performance indices for measuring 48.35 frequency and duration of service interruptions: 48.36 (a) The system average interruption frequency index is the 49.1 average number of interruptions per customer per year. It is 49.2 determined by dividing the total annual number of customer 49.3 interruptions by the average number of customers served during 49.4 the year. 49.5 (b) The system average interruption duration index is the 49.6 average customer-minutes of interruption per customer. It is 49.7 determined by dividing the annual sum of customer-minutes of 49.8 interruption by the average number of customers served during 49.9 the year. 49.10 (c) The customer average interruption duration index is the 49.11 average customer-minutes of interruption per customer 49.12 interruption. It approximates the average length of time 49.13 required to complete service restoration. It is determined by 49.14 dividing the annual sum of all customer-minutes of interruption 49.15 durations by the annual number of customer interruptions. 49.16 Sec. 2. [216B.81] [RECORDING SERVICE INTERRUPTION 49.17 INDEXES.] 49.18 Subdivision 1. [SYSTEM INTERRUPTION DATA.] Each electric 49.19 utility with 1,000 retail customers or more shall keep a record 49.20 of the necessary interruption data and calculate the system 49.21 average interruption frequency index, system average 49.22 interruption duration index, and customer average interruption 49.23 duration index of its system, and of each operating area, if 49.24 applicable, at the end of each calendar year for the previous 49.25 12-month period. 49.26 Subd. 2. [CIRCUIT INTERRUPTION DATA.] Each utility also 49.27 shall, at the end of each calendar year, calculate the system 49.28 average interruption frequency index, system average 49.29 interruption duration index, and customer average interruption 49.30 duration index for each circuit in each operating area. Each 49.31 circuit in each operating area must then be listed in order 49.32 separately according to its system average interruption 49.33 frequency index, its system average interruption duration index, 49.34 and its customer average interruption duration index, beginning 49.35 with the highest values for each index. 49.36 Sec. 3. [216B.82] [ANNUAL REPORT.] 50.1 Subdivision 1. [SUMMARY REPORT GENERALLY.] Beginning on 50.2 July 1, 2002, and by July 1 of every year thereafter, each 50.3 electric utility with 1,000 retail customers or more shall file 50.4 with the commission a report summarizing various measures of 50.5 reliability. The form of the report is subject to review and 50.6 approval by the commission staff. Names and numbers used to 50.7 identify operating areas or individual circuits may conform to 50.8 the utility's practice, but should allow ready identification of 50.9 the geographic location or the general area served. Electronic 50.10 recording and reporting of the required data and information is 50.11 encouraged. 50.12 Subd. 2. [INFORMATION REQUIRED.] (a) The report must 50.13 include at least the information described in paragraphs (b) to 50.14 (h). 50.15 (b) The report must provide an overall assessment of the 50.16 reliability of performance including the aggregate system 50.17 average interruption frequency index, system average 50.18 interruption duration index, and customer average interruption 50.19 duration index by system and each operating area, as applicable. 50.20 (c) The report must include a list of the worst performing 50.21 circuits based on system average interruption frequency index, 50.22 system average interruption duration index, and customer average 50.23 interruption duration index for the calendar year. This portion 50.24 of the report must describe the actions that the utility has 50.25 taken or will take to remedy the conditions responsible for each 50.26 listed circuit's unacceptable performance. The actions taken or 50.27 planned should be briefly described. Target dates for 50.28 corrective actions must be included in the report. When the 50.29 utility determines that actions on its part are unwarranted, its 50.30 report shall provide adequate justification for that conclusion. 50.31 (d) Utilities that use or prefer alternative criteria for 50.32 measuring individual circuit performance to those described in 50.33 paragraphs (b) and (c) and that are required by this section to 50.34 submit an annual report of reliability data, shall submit their 50.35 alternative listing of circuits along with the criteria used to 50.36 rank circuit performance. 51.1 (e) Information must be included with respect to any report 51.2 on the accomplishment of the improvements proposed in prior 51.3 reports for which completion has not been previously reported. 51.4 (f) The report must describe any new reliability or power 51.5 quality programs and changes that are made to existing programs. 51.6 (g) It must include a status report of any long-range 51.7 electric distribution plans. 51.8 (h) In addition to the information included in paragraph 51.9 (b), each utility shall report the following additional service 51.10 quality information: 51.11 (1) route miles of electric distribution line reconstructed 51.12 during the year, with separate totals for single- and 51.13 three-phase circuits provided; 51.14 (2) total route miles of electric distribution line in 51.15 service at year's end, segregated by voltage level; 51.16 (3) monthly average speed of answer for telephone calls 51.17 received regarding emergencies, outages, and customer billing 51.18 problems; 51.19 (4) the average number of calendar days a utility takes to 51.20 install and energize service to a customer site once it is ready 51.21 to receive service, with a separate average calculated for each 51.22 month, including all extensions energized during the calendar 51.23 month; 51.24 (5) the total number of written and telephone customer 51.25 complaints received in the areas of safety, customer billing, 51.26 outages, power quality, customer property damage, and other 51.27 areas, by month filed; 51.28 (6) total annual tree-trimming budget and actual expenses; 51.29 and 51.30 (7) total annual projected and actual miles of tree-trimmed 51.31 distribution line. 51.32 Sec. 4. [216B.83] [INITIAL HISTORICAL RELIABILITY 51.33 PERFORMANCE REPORT.] 51.34 (a) Each electric utility with 1,000 retail customers or 51.35 more that has historically used measures of system, operating 51.36 area, and circuit reliability performance shall initially submit 52.1 annual system average interruption frequency index, system 52.2 average interruption duration index, and customer average 52.3 interruption duration index data for the previous three years. 52.4 Those utilities that have this data for some time period less 52.5 than three years shall submit data for those years it is 52.6 available. 52.7 (b) Those utilities whose historical reliability 52.8 performance data is similar or related to those measures listed 52.9 in paragraph (a), but differs due to how the parameters are 52.10 defined or calculated, shall submit the data it has and explain 52.11 any material differences from the prescribed indices. After the 52.12 effective date of this section, utilities shall modify their 52.13 reliability performance measures to conform to those specified 52.14 in sections 216B.80 to 216B.86 for purposes of consistent 52.15 reporting of comparable data in the future. 52.16 Sec. 5. [216B.84] [INTERRUPTIONS OF SERVICE; RECORDS; 52.17 NOTICE.] 52.18 Subdivision 1. [RECORDS.] (a) Each utility shall keep 52.19 records of all interruptions to service affecting the entire 52.20 distribution system of any single community or an important 52.21 division of a community, and include in the records each 52.22 interruption's location, date and time, and duration; the 52.23 approximate number of customers affected; the circuit or 52.24 circuits involved; and, when known, the cause of each 52.25 interruption. 52.26 (b) When complete distribution systems or portions of 52.27 communities have service furnished from unattended stations, 52.28 these records must be kept to the extent practicable. The 52.29 record of unattended stations shall show interruptions that 52.30 require attention to restore service, with the estimated time of 52.31 interruption. Breaker or fuse operations affecting service 52.32 should also be indicated even though duration of interruption 52.33 may not be known. 52.34 Subd. 2. [NOTICE OF INTERRUPTIONS OF BULK POWER SUPPLY 52.35 FACILITIES.] (a) Each utility shall notify the commission of any 52.36 event described in paragraphs (b) to (f) involving any 53.1 generating unit or electric facilities operating at a nominal 53.2 voltage of 69 kilovolts or higher. 53.3 (b) Notice must be given for any interruption or loss of 53.4 service to customers for 15 minutes or more to aggregate firm 53.5 loads in excess of 200,000 kilowatts. This notification must be 53.6 made by telephone as soon as practicable without unduly 53.7 interfering with service restoration and, in any event, within 53.8 one hour after the beginning of the interruption. A confirming 53.9 written report must be submitted within two weeks. 53.10 (c) Any interruption or loss of service to customers for 15 53.11 minutes or more to aggregate firm loads exceeding the lesser of 53.12 100,000 kilowatts or one-half of the current annual system peak 53.13 load and not required to be reported under paragraph (b) must be 53.14 reported to the commission. This notification must be made by 53.15 telephone no later than the beginning of the commission's next 53.16 regular work day after the interruption occurred. A confirming 53.17 written report must be submitted within two weeks. 53.18 (d) A utility shall notify the commission of any decision 53.19 to issue a public request for reduction in use of electricity. 53.20 Notification of this decision must be made by telephone at the 53.21 time of issuing the request. A confirming written report must 53.22 be submitted within two weeks. 53.23 (e) An action to reduce firm customer loads by reduction of 53.24 voltage for reasons of maintaining adequacy of bulk electric 53.25 power supply must be reported to the commission. Notification 53.26 of this action must be made by telephone at the time of taking 53.27 the action. A confirming written report must be submitted 53.28 within two weeks. 53.29 (f) The utility shall notify the commission of any action 53.30 to reduce firm customer loads by manual switching, operation of 53.31 automatic load-shedding devices, or any other means for reasons 53.32 of maintaining adequacy of bulk electric power supply. 53.33 Notification of this action must be made by telephone at the 53.34 time of taking the action. 53.35 Subd. 3. [NOTICE OF OTHER INTERRUPTIONS OF POWER.] (a) 53.36 Each utility shall notify the commission of service 54.1 interruptions not involving bulk power supply facilities in 54.2 accordance with paragraph (b). 54.3 (b) Interruptions of 60 minutes or more to an entire 54.4 distribution substation bus or entire feeder serving either 500 54.5 or more customers or entire cities or villages having 200 or 54.6 more customers must be reported within two weeks by written 54.7 report. 54.8 Subd. 4. [INFORMATION REQUIRED.] The written reports 54.9 required in subdivisions 2 and 3 must include the date, time, 54.10 duration, general location, approximate number of customers 54.11 affected, identification of circuit or circuits involved, and, 54.12 when known, the cause of the interruption. When extensive 54.13 interruptions occur, as from a storm, a narrative report 54.14 including the extent of the interruptions and system damage, 54.15 estimated number of customers affected, and a list of entire 54.16 communities interrupted may be submitted in lieu of reports of 54.17 individual interruptions. 54.18 Sec. 6. [216B.85] [CUSTOMERS' COMPLAINTS.] 54.19 (a) Each utility shall investigate and keep a record of 54.20 complaints received by it from its customers in regard to 54.21 safety, service, or rates, and the operation of its system, with 54.22 appropriate response times designated for critical safety and 54.23 monetary loss situations. The record must show the name and 54.24 address of the complainant, the date and nature of the 54.25 complaint, the priority assigned to the assistance, and its 54.26 disposition and the time and date of its disposition. 54.27 (b) Each utility also shall document all contacts and 54.28 action relative to deferred payment agreements and disputes. 54.29 Sec. 7. [216B.86] [STANDARDS FOR DISTRIBUTION UTILITIES.] 54.30 (a) The commission shall adopt standards for safety, 54.31 reliability, and service quality for distribution utilities and 54.32 shall annually report on the aggregate performance of 54.33 Minnesota's distribution utilities relative to those standards. 54.34 (b) Reliability standards must be based on the system 54.35 average interruption frequency index, system average 54.36 interruption duration index, and customer average interruption 55.1 duration index measurement indices. Service quality standards 55.2 must specify: 55.3 (1) average call center response time; 55.4 (2) customer disconnection rate; 55.5 (3) meter-reading frequency; 55.6 (4) complaint resolution response time; and 55.7 (5) service extension request response time. 55.8 (c) Minimum performance standards developed under this 55.9 section must treat similarly situated distribution systems 55.10 similarly and recognize differing characteristics of system 55.11 design and hardware. 55.12 ARTICLE 6 55.13 CONFORMING AMENDMENTS 55.14 Section 1. Minnesota Statutes 2000, section 216B.16, 55.15 subdivision 6b, is amended to read: 55.16 Subd. 6b. [ENERGY CONSERVATION IMPROVEMENT.] (a) Except as 55.17 otherwise provided in this subdivision, all investments and 55.18 expenses of a public utility as defined in section 216B.241, 55.19 subdivision 1, paragraph (e)(g), incurred in connection with 55.20 energy conservation improvements shall be recognized and 55.21 included by the commission in the determination of just and 55.22 reasonable rates as if the investments and expenses were 55.23 directly made or incurred by the utility in furnishing utility 55.24 service. 55.25 (b) After December 31, 1999, investments and expenses for 55.26 energy conservation improvements shall not be included by the 55.27 commission in the determination of just and reasonable electric 55.28 and gas rates for retail electric and gas service provided to 55.29 large electric customer facilities that have been exempted by 55.30 the commissioner of the department of public service pursuant to 55.31 section 216B.241, subdivision 1a, paragraph (b). However, no 55.32 public utility shall be prevented from recovering its investment 55.33 in energy conservation improvements from all customers that were 55.34 made on or before December 31, 1999, in compliance with the 55.35 requirements of section 216B.241. 55.36 (c) The commission may permit a public utility to file rate 56.1 schedules providing for annual recovery of the costs of energy 56.2 conservation improvements. These rate schedules may be 56.3 applicable to less than all the customers in a class of retail 56.4 customers if necessary to reflect the differing minimum spending 56.5 requirements of section 216B.241, subdivision 1a. After 56.6 December 31, 1999, the commission shall allow a public utility, 56.7 without requiring a general rate filing under this section, to 56.8 reduce the electric and gas rates applicable to large electric 56.9 customer facilities that have been exempted by the commissioner 56.10 of the department of public service pursuant to section 56.11 216B.241, subdivision 1a, paragraph (b), by an amount that 56.12 reflects the elimination of energy conservation improvement 56.13 investments or expenditures for those facilities required on or 56.14 before December 31, 1999. In the event that the commission has 56.15 set electric or gas rates based on the use of an accounting 56.16 methodology that results in the cost of conservation 56.17 improvements being recovered from utility customers over a 56.18 period of years, the rate reduction may occur in a series of 56.19 steps to coincide with the recovery of balances due to the 56.20 utility for conservation improvements made by the utility on or 56.21 before December 31, 1999. 56.22 Sec. 2. Minnesota Statutes 2000, section 216B.1621, 56.23 subdivision 2, is amended to read: 56.24 Subd. 2. [COMMISSION APPROVAL.] (a) The commission shall 56.25 approve an agreement under this section upon finding that: 56.26 (1) the proposed electric service power generation facility 56.27 could reasonably be expected to qualify for a market value 56.28 exclusion under section 272.0211; 56.29 (2) the public utility has a contractual option to purchase 56.30 electric power from the proposed facility; and 56.31 (3) the public utility can use the output from the proposed 56.32 facility to meet its future need for power as demonstrated in 56.33 the most recent resource plan filed with and approved by the 56.34 commission under section 216B.2422. 56.35 (b) Sections 216B.03, 216B.05, 216B.06, 216B.07, 216B.16, 56.36 216B.162, and 216B.23 do not apply to an agreement under this 57.1 section. 57.2 Sec. 3. Minnesota Statutes 2000, section 216B.164, 57.3 subdivision 4, is amended to read: 57.4 Subd. 4. [PURCHASES; WHEELING; COSTS.] (a) Except as 57.5 otherwise provided in paragraph (c), this subdivision shall 57.6 apply to all qualifying facilities having 40-kilowatt capacity 57.7 or more as well as qualifying facilities as defined in 57.8 subdivision 3 which elect to be governed by its provisions. 57.9 (b) The utility to which the qualifying facility is 57.10 interconnected shall purchase all energy and capacity made 57.11 available by the qualifying facility. The qualifying facility 57.12 shall be paid the utility's full avoided capacity and energy 57.13 costs as negotiated by the parties, as set by the commission, or 57.14 as determined through competitive bidding approved by the 57.15 commission. The full avoided capacity and energy costs to be 57.16 paid a qualifying facility that generates electric power by 57.17 means of a renewable energy source are the utility's least cost 57.18 renewable energy facility or the bid of a competing supplier of 57.19 a least cost renewable energy facility, whichever is lower, 57.20 unless the commission's resource plan order , under section57.21 216B.2422, subdivision 2,provides that the use of a renewable 57.22 resource to meet the identified capacity need is not in the 57.23 public interest. 57.24 (c) For all qualifying facilities having 30-kilowatt 57.25 capacity or more, the utility shall, at the qualifying 57.26 facility's or the utility's request, provide wheeling or 57.27 exchange agreements wherever practicable to sell the qualifying 57.28 facility's output to any other Minnesota utility having 57.29 generation expansion anticipated or planned for the ensuing ten 57.30 years. The commission shall establish the methods and 57.31 procedures to insure that except for reasonable wheeling charges 57.32 and line losses, the qualifying facility receives the full 57.33 avoided energy and capacity costs of the utility ultimately 57.34 receiving the output. 57.35 (d) The commission shall set rates for electricity 57.36 generated by renewable energy. 58.1 Sec. 4. Minnesota Statutes 2000, section 216B.2421, 58.2 subdivision 1, is amended to read: 58.3 Subdivision 1. [APPLICABILITY.] The definition in this 58.4 section applies to this section and sections 216B.2422 and58.5 section 216B.243. 58.6 Sec. 5. Minnesota Statutes 2000, section 216B.2423, 58.7 subdivision 2, is amended to read: 58.8 Subd. 2. [RESOURCE PLANNING MANDATE.] The public utilities 58.9 commission shall order a public utility subject to subdivision 58.10 1, to construct and operate, purchase, or contract to purchase 58.11 an additional 400 megawatts of electric energy installed 58.12 capacity generated by wind energy conversion systems by December 58.13 31, 2002, subject to resource planning and least cost planning 58.14 requirements in section 216B.2422. 58.15 Sec. 6. Minnesota Statutes 2000, section 216B.243, 58.16 subdivision 3, is amended to read: 58.17 Subd. 3. [SHOWING REQUIRED FOR CONSTRUCTION.] No proposed 58.18 large energy facility shall be certified for construction unless 58.19 the applicant can show that demand for electricity cannot be met 58.20 more cost-effectively through energy conservation and 58.21 load-management measures and unless the applicant has otherwise 58.22 justified its need. In assessing need, the commission shall 58.23 evaluate: 58.24 (1) the accuracy of the long-range energy demand forecasts 58.25 on which the necessity for the facility is based; 58.26 (2) the effect of existing or possible energy conservation 58.27 programs under sections 216C.05 to 216C.30 and this section or 58.28 other federal or state legislation on long-term energy demand; 58.29 (3) the relationship of the proposed facility to overall 58.30 state energy needs, as described in the most recent state energy 58.31 policy and conservation report prepared under section 216C.18; 58.32 (4) promotional activities that may have given rise to the 58.33 demand for this facility; 58.34 (5) socially beneficial uses of the output of this 58.35 facility, including its uses to protect or enhance environmental 58.36 quality; 59.1 (6) the effects of the facility in inducing future 59.2 development; 59.3 (7) possible alternatives for satisfying the energy demand 59.4 including but not limited to potential for increased efficiency 59.5 of existing energy generation facilities; 59.6 (8) the policies, rules, and regulations of other state and 59.7 federal agencies and local governments; and 59.8 (9) any feasible combination of energy conservation 59.9 improvements, required under section 216B.241, that can (i) 59.10 replace part or all of the energy to be provided by the proposed 59.11 facility, and (ii) compete with it economically. 59.12 Sec. 7. Minnesota Statutes 2000, section 216C.17, 59.13 subdivision 3, is amended to read: 59.14 Subd. 3. [DUPLICATION.] The commissioner shall, to the 59.15 maximum extent feasible, provide that forecasts required under 59.16 this section be consistent with material required by other state 59.17 and federal agencies in order to prevent unnecessary 59.18 duplication. Electric utilities submitting advance forecasts as59.19 part of an integrated resource plan filed pursuant to section59.20 216B.2422 and public utilities commission rules are excluded59.21 from the annual reporting requirement in subdivision 2.