1st Engrossment - 82nd Legislature (2001 - 2002) Posted on 12/15/2009 12:00am
1.1 A bill for an act 1.2 relating to energy; enacting the Minnesota Energy 1.3 Security and Reliability Act; requiring an energy 1.4 security blueprint and a state reliability plan; 1.5 providing for essential energy infrastructure; 1.6 eliminating the requirement for individual utility 1.7 plans; creating an independent reliability 1.8 administrator; modifying provisions for siting, 1.9 routing, and determining the need for large electric 1.10 power facilities; regulating conservation expenditures 1.11 by energy utilities and eliminating state pre-approval 1.12 of conservation plans by public utilities; encouraging 1.13 regulatory flexibility in supplying and obtaining 1.14 energy; regulating interconnection of distributed 1.15 utility resources; providing for safety and service 1.16 standards from distribution utilities; clarifying the 1.17 state cold weather disconnection requirements; making 1.18 technical, conforming, and clarifying changes; 1.19 amending Minnesota Statutes 2000, sections 116.07, 1.20 subdivision 4a; 116C.52, subdivision 4; 116C.53, 1.21 subdivision 3; 116C.57, subdivisions 1, 2, 4, by 1.22 adding subdivisions; 116C.58; 116C.59, subdivision 1; 1.23 116C.60; 116C.61, subdivision 1; 116C.62; 116C.64; 1.24 116C.645; 116C.65; 116C.66; 116C.69; 216A.03, 1.25 subdivision 3a; 216B.03; 216B.095; 216B.097, 1.26 subdivision 1; 216B.16, subdivisions 1, 6b, 6c, 7, by 1.27 adding a subdivision; 216B.162, subdivision 8; 1.28 216B.1621, subdivision 2; 216B.164, subdivision 4; 1.29 216B.241, subdivisions 1, 1a, 1b, 2, 2a, by adding 1.30 subdivisions; 216B.2421, subdivision 2, by adding a 1.31 subdivision; 216B.2423, subdivision 2; 216B.243, 1.32 subdivisions 2, 3, 4, by adding a subdivision; 1.33 216B.42, subdivision 1; 216C.17, subdivision 3; 1.34 216C.41; proposing coding for new law in Minnesota 1.35 Statutes, chapters 116C; 216B; repealing Minnesota 1.36 Statutes 2000, sections 116C.55; 116C.57, subdivisions 1.37 3, 5, 5a; 116C.67; 216B.241, subdivision 1c; 1.38 216B.2422, subdivisions 2, 6; 216C.18. 1.39 BE IT ENACTED BY THE LEGISLATURE OF THE STATE OF MINNESOTA: 1.40 ARTICLE 1 1.41 ENERGY PLANNING 1.42 Section 1. [TITLE.] 2.1 This act shall be known as the Minnesota Energy Security 2.2 and Reliability Act. 2.3 Sec. 2. [216B.011] [ADMINISTRATOR; ASSESSMENTS; 2.4 APPROPRIATION; REPORT.] 2.5 Subdivision 1. [CREATION.] (a) Recognizing the critical 2.6 importance of adequate, reliable, and environmentally sound 2.7 energy services to the state's economy and the well-being of its 2.8 citizens, and that responsibility for reliability is dispersed 2.9 among several state agencies, the commissioner of commerce shall 2.10 create an independent reliability administrator within the 2.11 department of commerce. 2.12 (b) The commissioner, with the advice and consent of the 2.13 commission, shall appoint the administrator for a term 2.14 concurrent with that of the governor. The administrator may be 2.15 removed only for cause. In addition to jointly appointing the 2.16 administrator, the commissioner, the commission chair, and the 2.17 director of the office of strategic and long-range planning 2.18 shall oversee and direct the work of the administrator, annually 2.19 audit the expenses of the administrator, and biennially approve 2.20 the budget of the administrator. 2.21 (c) The administrator may utilize staff from the 2.22 department, commission, and the board, at the discretion of the 2.23 administrative heads of those agencies; may hire staff; and may 2.24 contract for technical expertise in performing duties when 2.25 existing state resources are required for other state 2.26 responsibilities or when special expertise is required. 2.27 (d) The salary of the administrator is governed by section 2.28 15A.0815, subdivision 2. 2.29 Subd. 2. [DUTIES.] (a) The administrator shall increase 2.30 state agency technical expertise and understanding of 2.31 reliability needs and increase public confidence in proposed 2.32 infrastructure projects by: 2.33 (1) modeling and monitoring the use and operation of the 2.34 energy infrastructure in the state, including generation 2.35 facilities, transmission lines, natural gas pipelines, and other 2.36 energy infrastructure; 3.1 (2) identifying weaknesses, constraints, and conditions 3.2 that materially limit the adequacy of energy supply, efficiency 3.3 of energy service, or reliability of energy service to consumers 3.4 in Minnesota that may require construction of a generation, 3.5 transmission, or natural gas pipeline project; 3.6 (3) developing and consolidating technical analyses of 3.7 proposed infrastructure projects, to be utilized by the 3.8 commission, the department, the office of attorney general, the 3.9 environmental quality board, and the pollution control agency in 3.10 reviewing applications for infrastructure approvals under the 3.11 jurisdiction of those respective agencies; 3.12 (4) assessing, from a technical standpoint, assertions of 3.13 need for additional infrastructure for the members of the 3.14 regional energy infrastructure planning groups; 3.15 (5) developing, issuing, and presenting the reliability 3.16 status report required under subdivision 4 and the state 3.17 reliability plan under section 216B.012; 3.18 (6) hosting public meetings around the state to present 3.19 independent, factual, expert, technical information on 3.20 infrastructure proposals; and 3.21 (7) coordinating with regional energy infrastructure 3.22 planning groups; regulators and reliability officials of other 3.23 states; regional reliability entities; and the federal 3.24 government. 3.25 (b) The commission, department, and environmental quality 3.26 board shall refer applications for transmission infrastructure 3.27 approvals to the administrator for initial technical analysis of 3.28 the proposed infrastructure improvement on reliability of energy 3.29 services to Minnesota consumers. The administrator shall 3.30 provide written and oral technical assistance on the application 3.31 to each referring agency, and shall provide such advice and 3.32 analysis as that agency deems necessary. 3.33 (c) The administrator shall certify its administrative 3.34 costs to the commission on a monthly basis, and shall specify 3.35 those costs that are general in nature, and those that were 3.36 incurred on a specific application or with regard to a specific 4.1 utility. The commission shall review those costs, and shall 4.2 order payment within 30 days of commission review. The 4.3 department shall render a bill to the utility or utilities, 4.4 either at the conclusion of the proceeding, analysis, or 4.5 service, or from time to time during the course of the 4.6 proceeding, analysis, or service. The bill constitutes notice 4.7 of the assessment and a demand for payment. The amount of the 4.8 bills so rendered by the department must be paid by the public 4.9 utility into the state treasury within 30 days from the date of 4.10 billing and are appropriated to the administrator for the 4.11 purposes provided in this section. General administrative costs 4.12 of the administrator must not exceed $2,000,000 for a fiscal 4.13 biennium; however, additional amounts may be incurred and 4.14 recovered above this amount, if the commissioner and chair of 4.15 the commission deem the additional amounts to be necessary. The 4.16 administrator shall provide a detailed accounting of its 4.17 finances to the commissioner and to the chairs of the house and 4.18 senate finance committees with jurisdiction over the 4.19 department's budget. Costs that are of a general nature must be 4.20 apportioned among all energy utilities in proportion to their 4.21 respective gross operating revenues from retail sales of gas or 4.22 electric service within the state during the last calendar 4.23 year. Within 30 days after the date of the mailing of any bill 4.24 as provided by this subdivision and subdivision 3, the utility 4.25 against which the bill has been rendered may file with the 4.26 commission objections setting out the grounds upon which it is 4.27 claimed the bill is excessive, erroneous, unlawful, or invalid. 4.28 Within 60 days, the commission shall hold a hearing and issue an 4.29 order in accordance with its findings. The order is appealable 4.30 in the same manner as other final orders of the commission. The 4.31 commission shall approve or approve as modified a rate schedule 4.32 providing for the automatic adjustment of charges to recover 4.33 amounts paid by utilities under this section. 4.34 Subd. 3. [TECHNICAL ASSISTANCE.] Upon request, the 4.35 administrator shall provide technical assistance regarding 4.36 matters unrelated to applications for infrastructure 5.1 improvements to the department, the commission, and the board. 5.2 Subd. 4. [RELIABILITY STATUS REPORT.] (a) The commission 5.3 shall require all distribution utilities, as technically and 5.4 administratively feasible, to report to the administrator on 5.5 operating and planning reserves, available transmission 5.6 capacity, outages of major generation units and feeders of 5.7 distribution and transmissions facilities, the adequacy of stock 5.8 and equipment, and any other information necessary to assess the 5.9 current and future reliability of energy service in this state. 5.10 Distribution utilities that are currently required to file 5.11 resource plans may submit updates, if applicable. 5.12 (b) The administrator shall, by January 1 of each 5.13 odd-numbered year beginning in 2003, assess and report to the 5.14 commissioner, with copies to the commission and the chairs of 5.15 the house and senate committees with jurisdiction over energy 5.16 policy issues, the status of the reliability of electric service 5.17 in the state and make recommendations, if applicable, for 5.18 regulatory or legislative action. 5.19 Sec. 3. [216B.012] [STATE RELIABILITY PLAN.] 5.20 (a) By January 1 of every odd-numbered year, the 5.21 administrator shall develop and present to the commissioner 5.22 recommendations for a draft state reliability plan, consisting 5.23 of critical transmission system upgrades and new transmission 5.24 projects of 100 kilovolts or greater. Only projects that, in 5.25 the opinion of the administrator, meet the criteria established 5.26 in section 216B.243 for issuing certificates of need and public 5.27 purpose designations for large energy facilities may be 5.28 recommended to be included in the draft administrator's 5.29 recommendations. The plan may describe projects generally. 5.30 Specific locations and routes must be determined by the 5.31 environmental quality board as provided in section 116C.57 or 5.32 116C.575. 5.33 (b) In developing the administrator's recommendations, the 5.34 administrator shall consider: 5.35 (1) the most recent state energy security blueprint issued 5.36 under section 216B.015; 6.1 (2) the most recent regional energy infrastructure reports 6.2 issued by the regional energy infrastructure planning regions; 6.3 (3) any transmission plan issued by a federally approved 6.4 regional reliability entity for the region that includes 6.5 Minnesota, or issued by the reliability entity for this region 6.6 that is a member of the North American Electric Reliability 6.7 Council, or any successor organization; 6.8 (4) any deficiencies noticed under section 216B.019, 6.9 subdivision 5; 6.10 (5) any transmission plan developed and proposed jointly by 6.11 the transmission-owning or transmission-operating entities in 6.12 the state; 6.13 (6) the needs of transmission-dependent utilities and 6.14 customers in Minnesota; and 6.15 (7) any other information the administrator deems necessary 6.16 or reasonable. 6.17 (c) Each energy utility, energy service supplier, or 6.18 transmission owner or operator shall comply with all requests 6.19 for information that the administrator deems necessary to 6.20 complete the proposed plan. 6.21 (d) Within 30 days of receiving the administrator's 6.22 recommendations, the commissioner shall propose a state 6.23 reliability plan to the commission. The commission shall 6.24 approve, reject, or approve as modified the plan proposed by the 6.25 administrator within 180 days of issuance and shall publish the 6.26 plan in the State Register. In making its decision under this 6.27 paragraph, the commission shall impose the criteria and 6.28 procedures established in section 216B.243 for issuing 6.29 certificates of need and public purpose designations. Each 6.30 project in a state reliability plan approved by the commission 6.31 is exempt from additional commission review under section 6.32 216B.243. 6.33 (e) The administrator shall hold public meetings in all 6.34 areas of the state affected by the reliability plan. 6.35 (f) This chapter may not be construed to undermine the 6.36 existing and continuing obligation of the public utilities, 7.1 municipal utilities, and cooperative electric associations that 7.2 operate and provide service in this state to be ultimately 7.3 responsible for (1) providing reliable, affordable, safe, and 7.4 efficient energy services to their customers in this state, (2) 7.5 planning to meet the resource and infrastructure needs of those 7.6 customers, or (3) ensuring that those resources and 7.7 infrastructure are sited and constructed or otherwise acquired. 7.8 Sec. 4. [216B.013] [EXISTING GENERATION FACILITIES.] 7.9 In order to continue the low-maintenance and low-cost 7.10 service that the existing base-load generation facilities in 7.11 Minnesota have provided to Minnesota consumers, and to provide 7.12 power to meet the growing demand for electricity by Minnesota 7.13 consumers and businesses, it is the policy of the state that 7.14 these facilities be maintained and upgraded consistent with 7.15 energy policy goals established pursuant to this chapter. The 7.16 public utilities commission, department, and other state 7.17 agencies with regulatory jurisdiction over the operation of 7.18 these facilities shall take all steps necessary to incorporate 7.19 this state policy into the regulatory decisions made by each 7.20 respective agency. 7.21 Sec. 5. [216B.014] [ENERGY SECURITY AND RELIABILITY.] 7.22 (a) It is a fundamental goal of Minnesota's energy and 7.23 utility policy that state policymakers maximize the state's 7.24 energy security. 7.25 (b) "Energy security" means, among other things, ensuring 7.26 that the state's energy sources are: 7.27 (1) diverse, including (i) traditional sources such as 7.28 coal, natural gas, waste-to-energy, and nuclear facilities, (ii) 7.29 renewable sources such as wind, biomass, and agricultural waste 7.30 generation, and (iii) high-efficiency, low-emissions distributed 7.31 generation sources such as fuel cells and microturbines; 7.32 (2) to the extent feasible, produced in the state; 7.33 (3) environmentally sustainable; 7.34 (4) available to consumers at affordable and stable rates 7.35 or prices; and 7.36 (5) above all, reliable. "Reliable" means, among other 8.1 things, that adequate resources and infrastructure are in place, 8.2 and are planned for, to provide efficient, dependable, and 8.3 secure energy services to Minnesota consumers. 8.4 Sec. 6. [216B.015] [ENERGY SECURITY BLUEPRINT.] 8.5 (a) The commissioner shall develop a draft energy security 8.6 blueprint by March 1, 2002, and every four years thereafter. 8.7 The blueprint must: 8.8 (1) identify important trends and issues in energy supply, 8.9 consumption, conservation, and costs; 8.10 (2) set energy goals; and 8.11 (3) develop strategies to meet the goals. 8.12 (b) For the purposes of sections 216B.012 to 216B.019, the 8.13 terms: 8.14 (1) "electric utility" means an entity that is a public 8.15 utility; a cooperative electric association providing 8.16 generation, transmission, or distribution services; a municipal 8.17 utility; or a municipal power agency; and 8.18 (2) "energy utility" means an electric utility, or an 8.19 entity providing natural gas to retail consumers. 8.20 Sec. 7. [216B.016] [ENERGY BLUEPRINT CONTENTS.] 8.21 The energy blueprint must include: 8.22 (1) the amount and type of projected statewide energy 8.23 consumption over the next ten years; 8.24 (2) a determination of whether and the extent to which 8.25 existing and anticipated energy production and transportation 8.26 facilities will or will not be able to supply needed energy; 8.27 (3) a determination of the potential for conservation to 8.28 meet some or all of the projected need for energy; 8.29 (4) an assessment of the environmental impact of projected 8.30 energy consumption over the next ten years, prepared by the 8.31 commissioner of the pollution control agency in consultation 8.32 with other state agencies and other interested persons, with 8.33 strategies to mitigate those impacts; and 8.34 (5) benchmarks to measure and monitor supply adequacy and 8.35 infrastructure capacity, and to assess the overall reliability 8.36 of the state's electric system. 9.1 Sec. 8. [216B.017] [ENERGY GOALS.] 9.2 (a) The blueprint must recommend statewide goals and list 9.3 strategies to accomplish the following goals for: 9.4 (1) energy conservation and recovery; 9.5 (2) limiting adverse environmental emissions from the 9.6 generation of electric energy consumed in the state; 9.7 (3) production of electric energy consumed in the state 9.8 from renewable energy sources; 9.9 (4) deployment of distributed electric generation 9.10 technologies; 9.11 (5) ensuring that energy service is affordable and 9.12 available to all consumers in the state; 9.13 (6) minimizing the imposition of social costs on energy 9.14 consumers through energy rates or prices; and 9.15 (7) increasing the efficiency of the regulatory 9.16 infrastructure and reducing regulatory and administrative costs. 9.17 (b) The goals adopted in the blueprint may be one-time 9.18 goals or a series of goals to meet overall objectives. The 9.19 commissioner and the administrator shall jointly present these 9.20 goals, and any associated strategies that require changes to 9.21 state law, to the legislature for modification and approval. 9.22 Sec. 9. [216B.018] [BLUEPRINT DEVELOPMENT.] 9.23 Subdivision 1. [PUBLIC PARTICIPATION.] The commissioner 9.24 shall: 9.25 (1) invite public and stakeholder comment and participation 9.26 during blueprint development; and 9.27 (2) hold at least one public meeting on the proposed 9.28 blueprint in each energy infrastructure planning region of the 9.29 state after at least 30 days' public notice in the region. 9.30 Subd. 2. [NOTICE AND COMMENT; BLUEPRINT ISSUANCE.] The 9.31 commissioner shall provide notice of all public meetings to 9.32 discuss the proposed blueprint and allow opportunity for written 9.33 comment prior to issuing the final blueprint. After review by 9.34 the administrator, the commissioner shall publish the final 9.35 energy blueprint in the State Register within four months of 9.36 issuing the draft blueprint. 10.1 Sec. 10. [216B.019] [REGIONAL ENERGY INFRASTRUCTURE 10.2 PLANNING.] 10.3 Subdivision 1. [ESTABLISHING PLANNING REGIONS.] The 10.4 commission, after notice and opportunity for written comment, 10.5 shall establish geographic regional energy infrastructure 10.6 planning regions in the state by August 1, 2001. Planning 10.7 regions may coincide with existing subregional planning areas 10.8 used by the regional electric reliability or regional 10.9 transmission organization serving Minnesota. 10.10 Subd. 2. [PLANNING GROUP.] Each energy utility that 10.11 operates in an identified region shall participate in the 10.12 regional energy infrastructure planning group. Each regional 10.13 group must include as voting members an equal number of 10.14 representatives of energy utilities, and representatives from 10.15 counties in the identified region, appointed by the county board. 10.16 Subd. 3. [PUBLIC MEETINGS.] Each regional energy 10.17 infrastructure planning group shall hold public meetings within 10.18 the region on a regular basis and provide public notice at least 10.19 14 calendar days in advance of a meeting. 10.20 Subd. 4. [REPORT.] By December 31, 2001, and every two 10.21 years thereafter, each regional energy infrastructure planning 10.22 group shall submit a report to the commissioner that: 10.23 (1) identifies inadequacies in electric generation and 10.24 transmission within the region including any deficiencies as 10.25 defined in subdivision 5; 10.26 (2) lists alternative ways to address identified 10.27 inadequacies, taking into account the provisions of the state 10.28 energy security blueprint; 10.29 (3) identifies potential general and, to the extent known, 10.30 specific economic, environmental, and social issues associated 10.31 with each alternative; and 10.32 (4) recommends alternatives to address identified 10.33 inadequacies and deficiencies that ensure the reliability and 10.34 security of the energy system in the region, while minimizing 10.35 environmental and social impacts. In making recommendations, 10.36 the planning group shall identify critical needs. For the 11.1 purposes of this clause, "critical needs" are those projects 11.2 that are necessary to maintain reliable electric service to 11.3 Minnesota consumers that meet or exceed the most stringent 11.4 applicable state or regional reliability standards. 11.5 Subd. 5. [DEFICIENCY.] (a) "Deficiency" means a condition, 11.6 or set of conditions, that materially limit the adequacy of 11.7 electric supply, efficiency of electric service, or reliability 11.8 of electric service to an electric utility's customers in the 11.9 state that may require construction of a generation or 11.10 transmission project. 11.11 (b) Within 90 days of identifying a deficiency in its 11.12 system, an electric utility shall give notice of the deficiency 11.13 to at least: 11.14 (1) the members of affected regional energy infrastructure 11.15 planning groups; 11.16 (2) officials of potentially affected local governments; 11.17 and 11.18 (3) the commissioner and the independent reliability 11.19 administrator. 11.20 (c) Notice of deficiency must be made before submitting (1) 11.21 an application for a certificate of need under section 216B.243 11.22 or (2) a request for environmental review of an energy project 11.23 to any governmental entity. 11.24 Sec. 11. [EFFECTIVE DATES.] 11.25 Sections 2 and 3 are effective July 1, 2002. The rest of 11.26 this article is effective the day following final enactment. 11.27 ARTICLE 2 11.28 ESSENTIAL ENERGY INFRASTRUCTURE 11.29 Section 1. Minnesota Statutes 2000, section 116.07, 11.30 subdivision 4a, is amended to read: 11.31 Subd. 4a. [PERMITS.] (a) The pollution control agency may 11.32 issue, continue in effect, or deny permits, undersuch11.33 conditionsasit may prescribe for the prevention of pollution, 11.34 for (1) the emission of air contaminants except for emissions 11.35 from electric generation stations,or for(2) the installation 11.36 or operation of any emission facility, air contaminant treatment 12.1 facility, treatment facility, potential air contaminant storage 12.2 facility, or storage facility, or any part thereof,or for(3) 12.3 the sources or emissions of noise pollution.12.4The pollution control agency may also issue, continue in12.5effect or deny permits, under such conditions as it may12.6prescribe for the prevention of pollution, for, (4) the 12.7 emissions of air contaminants from electric generation stations, 12.8 (5) the storage, collection, transportation, processing, or 12.9 disposal of waste, orfor(6) the installation or operation of 12.10 any system or facility, or any part thereof, related to the 12.11 storage, collection, transportation, processing, or disposal of 12.12 waste. 12.13 The pollution control agency may revoke or modify any permit 12.14 issued under this subdivision and section 116.081 whenever it is 12.15 necessary, in the opinion of the agency, to prevent or abate 12.16 pollution. 12.17 (b) The pollution control agency has the authority for 12.18 approval over the siting, expansion, or operation of a solid 12.19 waste facility with regard to environmental issues. However, 12.20 the agency's issuance of a permit does not release the permittee 12.21 from any liability, penalty, or duty imposed by any applicable 12.22 county ordinances. Nothing in this chapter precludes, or shall 12.23 be construed to preclude, a county from enforcing land use 12.24 controls, regulations, and ordinances existing at the time of 12.25 the permit application and adopted pursuant to sections 366.10 12.26 to 366.181, 394.21 to 394.37, or 462.351 to 462.365, with regard 12.27 to the siting, expansion, or operation of a solid waste facility. 12.28 Sec. 2. Minnesota Statutes 2000, section 116C.52, 12.29 subdivision 4, is amended to read: 12.30 Subd. 4. [HIGH VOLTAGE TRANSMISSION LINE.] "High voltage 12.31 transmission line" means a conductor of electric energy and 12.32 associated facilities designed for and capable of operation at a 12.33 nominal voltage of200100 kilovolts or more, except that the12.34board, by rule, may exempt lines pursuant to section 116C.57,12.35subdivision 5. 12.36 Sec. 3. Minnesota Statutes 2000, section 116C.53, 13.1 subdivision 3, is amended to read: 13.2 Subd. 3. [INTERSTATE ROUTES.] (a) If a route is proposed 13.3 in two or more states, the board shall attempt to reach 13.4 agreement with affected states on the entry and exit points 13.5 prior to authorizing the construction of the route. The board, 13.6 in discharge of its duties pursuant to sections 116C.51 to 13.7 116C.69 may make joint investigations, hold joint hearings 13.8 within or without the state, and issue joint or concurrent 13.9 orders in conjunction or concurrence with any official or agency 13.10 of any state or of the United States. The board may negotiate 13.11 and enter into any agreements or compacts with agencies of other 13.12 states, pursuant to any consent of Congress, for cooperative 13.13 efforts in certifying the construction, operation, and 13.14 maintenance of large electric power facilities in accord with 13.15 the purposes of sections 116C.51 to 116C.69 and for the 13.16 enforcement of the respective state laws regardingsuchthese 13.17 facilities. 13.18 (b) The board may not issue a route permit for the 13.19 Minnesota portion of an interstate high voltage transmission 13.20 line unless the applicant has received a certificate of need 13.21 from the public utilities commission. 13.22 Sec. 4. Minnesota Statutes 2000, section 116C.57, 13.23 subdivision 1, is amended to read: 13.24 Subdivision 1. [DESIGNATION OF SITES SUITABLE FOR SPECIFIC13.25FACILITIES; REPORTSSITE PERMIT.]A utility must apply to the13.26board in a form and manner prescribed by the board for13.27designation of a specific site for a specific size and type of13.28facility. The application shall contain at least two proposed13.29sites. In the event a utility proposes a site not included in13.30the board's inventory of study areas, the utility shall specify13.31the reasons for the proposal and shall make an evaluation of the13.32proposed site based upon the planning policies, criteria and13.33standards specified in the inventory. Pursuant to sections13.34116C.57 to 116C.60, the board shall study and evaluate any site13.35proposed by a utility and any other site the board deems13.36necessary which was proposed in a manner consistent with rules14.1adopted by the board concerning the form, content, and14.2timeliness of proposals for alternate sites. No site14.3designation shall be made in violation of the site selection14.4standards established in section 116C.55. The board shall14.5indicate the reasons for any refusal and indicate changes in14.6size or type of facility necessary to allow site designation.14.7Within a year after the board's acceptance of a utility's14.8application, the board shall decide in accordance with the14.9criteria specified in section 116C.55, subdivision 2, the14.10responsibilities, procedures and considerations specified in14.11section 116C.57, subdivision 4, and the considerations in14.12chapter 116D which proposed site is to be designated. The board14.13may extend for just cause the time limitation for its decision14.14for a period not to exceed six months. When the board14.15designates a site, it shall issue a certificate of site14.16compatibility to the utility with any appropriate conditions.14.17The board shall publish a notice of its decision in the State14.18Register within 30 days of site designation.No person may 14.19 construct a large electric power generating plantshall be14.20constructed except onwithout a sitedesignated bypermit from 14.21 the board or a county. A large electric generating plant may be 14.22 constructed only on either (1) a site approved by the board 14.23 under this section or section 116C.575, or (2) a site designated 14.24 by a county using terms, conditions, procedures, and standards 14.25 no less stringent than those imposed and used by the board. 14.26 Sec. 5. Minnesota Statutes 2000, section 116C.57, 14.27 subdivision 2, is amended to read: 14.28 Subd. 2. [DESIGNATION OF ROUTES; PROCEDUREROUTE PERMIT.] 14.29A utility shall apply to the board in a form and manner14.30prescribed by the board for a permit for the construction of a14.31high voltage transmission line. The application shall contain14.32at least two proposed routes. Pursuant to sections 116C.57 to14.33116C.60, the board shall study, and evaluate the type, design,14.34routing, right-of-way preparation and facility construction of14.35any route proposed in a utility's application and any other14.36route the board deems necessary which was proposed in a manner15.1consistent with rules adopted by the board concerning the form,15.2content, and timeliness of proposals for alternate routes15.3provided, however, that the board shall identify the alternative15.4routes prior to the commencement of public hearings thereon15.5pursuant to section 116C.58. Within one year after the board's15.6acceptance of a utility's application, the board shall decide in15.7accordance with the criteria and standards specified in section15.8116C.55, subdivision 2, and the considerations specified in15.9section 116C.57, subdivision 4, which proposed route is to be15.10designated. The board may extend for just cause the time15.11limitation for its decision for a period not to exceed 90 days.15.12When the board designates a route, it shall issue a permit for15.13the construction of a high voltage transmission line specifying15.14the type, design, routing, right-of-way preparation and facility15.15construction it deems necessary and with any other appropriate15.16conditions. The board may order the construction of high15.17voltage transmission line facilities which are capable of15.18expansion in transmission capacity through multiple circuiting15.19or design modifications. The board shall publish a notice of15.20its decision in the state register within 30 days of issuance of15.21the permit.(a) No person may construct a high voltage 15.22 transmission lineshall be constructed except onwithout a route 15.23designated bypermit from the board or by a county pursuant to 15.24 paragraph (b), unless it was exempted pursuant to subdivision15.255. A high voltage transmission line may be constructed only 15.26 along a route approved by the board under this section or 15.27 section 116C.575, or by a county pursuant to paragraph (b). 15.28 (b) A high voltage transmission line of between 100 and 200 15.29 kilovolts may be permitted and routed by a county using terms, 15.30 conditions, procedures, and standards no less stringent than 15.31 those imposed and used by the board, unless the county requests 15.32 the board to route the proposed line. 15.33 Sec. 6. Minnesota Statutes 2000, section 116C.57, is 15.34 amended by adding a subdivision to read: 15.35 Subd. 2a. [APPLICATION.] (a) A person seeking to construct 15.36 a large electric power generating plant or a high voltage 16.1 transmission line shall apply to the board for a site permit or 16.2 route permit. The application must contain any information 16.3 required by the board and must specify: 16.4 (1) whether the applicant is required to receive a 16.5 certificate of need for the proposed project; 16.6 (2) whether the applicant is required to comply with 16.7 section 216B.019, subdivision 5, and has complied; 16.8 (3) whether the proposed project was identified, discussed, 16.9 and considered by the relevant regional energy infrastructure 16.10 planning group and the result of that consideration. 16.11 (b) The applicant shall propose at least two sites for a 16.12 large electric power generating plant and two routes for a high 16.13 voltage transmission line. 16.14 (c) The chair of the board shall determine whether an 16.15 application is complete and advise the applicant of any 16.16 deficiencies. 16.17 Sec. 7. Minnesota Statutes 2000, section 116C.57, is 16.18 amended by adding a subdivision to read: 16.19 Subd. 2b. [NOTICE OF APPLICATION.] Within 15 days after 16.20 submitting an application to the board, the applicant shall 16.21 publish notice of the application in a legal newspaper of 16.22 general circulation in each county in which the site or route is 16.23 proposed and send a copy of the application by certified mail to 16.24 any regional development commission, county, incorporated 16.25 municipality, and town in which the site or route is proposed. 16.26 Within the same 15 days, the applicant shall also send a notice 16.27 of the submission of the application and description of the 16.28 proposed project to each owner whose property is adjacent to any 16.29 of the proposed sites for the power plant or along any of the 16.30 proposed routes for the transmission line. The notice must 16.31 identify a location where a copy of the application can be 16.32 reviewed. For the purpose of giving mailed notice under this 16.33 subdivision, owners are those shown on the records of the county 16.34 auditor or, in any county where tax statements are mailed by the 16.35 county treasurer, on the records of the county treasurer, but 16.36 other appropriate records may be used for this purpose. The 17.1 failure to give mailed notice to a property owner, or defects in 17.2 the notice, does not invalidate the proceedings, provided a bona 17.3 fide attempt to comply with this subdivision has been made. 17.4 Within the same 15 days, the applicant shall also send the same 17.5 notice of the submission of the application and description of 17.6 the proposed project to those persons who have requested to be 17.7 placed on a list maintained by the board for receiving notice of 17.8 proposed large electric generating power plants and high voltage 17.9 transmission lines. 17.10 Sec. 8. Minnesota Statutes 2000, section 116C.57, is 17.11 amended by adding a subdivision to read: 17.12 Subd. 2c. [ENVIRONMENTAL REVIEW.] (a) After a complete 17.13 application has been submitted, an environmental impact 17.14 statement must be prepared by the board for each proposed large 17.15 electric generating plant and for each proposed high voltage 17.16 transmission line. 17.17 (b) The board shall not consider the no-build alternative 17.18 for any project that is required to have a certificate of need 17.19 from the public utilities commission. 17.20 (c) No other state environmental review documents are 17.21 required. 17.22 (d) The board shall study and evaluate any site or route 17.23 proposed by an applicant, in addition to any other site or route 17.24 the board deems necessary that was proposed in a manner 17.25 consistent with rules adopted by the board concerning the form, 17.26 content, and timeliness of proposals for alternate sites or 17.27 routes. 17.28 Sec. 9. Minnesota Statutes 2000, section 116C.57, is 17.29 amended by adding a subdivision to read: 17.30 Subd. 2d. [PUBLIC HEARING.] The board and the independent 17.31 reliability administrator shall hold a joint public hearing on 17.32 an application for a site permit for a large electric power 17.33 generating plant or a route permit for a high voltage 17.34 transmission line. A hearing held for designating a site or 17.35 route must be conducted by an administrative law judge from the 17.36 office of administrative hearings under the contested case 18.1 procedures of chapter 14. Notice of the hearing must be given 18.2 by the board at least ten days in advance but no earlier than 45 18.3 days prior to the commencement of the hearing. Notice must be 18.4 by publication in a legal newspaper of general circulation in 18.5 the county in which the public hearing is to be held and by 18.6 certified mail to chief executives of the regional development 18.7 commissions, counties, organized towns, townships, and the 18.8 incorporated municipalities in which a site or route is 18.9 proposed. A person may appear at the hearing and offer 18.10 testimony and exhibits without the necessity of intervening as a 18.11 formal party to the proceeding. The administrative law judge 18.12 may allow a person to ask questions of other witnesses. The 18.13 administrative law judge shall hold a portion of the hearing in 18.14 the area where the power plant or transmission line is proposed 18.15 to be located. 18.16 Sec. 10. Minnesota Statutes 2000, section 116C.57, 18.17 subdivision 4, is amended to read: 18.18 Subd. 4. [CONSIDERATIONS IN DESIGNATING SITES AND 18.19 ROUTES.] (a) To facilitate the study, research, evaluation, and 18.20 designation of sites and routes, the board shall be guided by, 18.21 but not limited to, the following responsibilities, procedures, 18.22 and considerations: 18.23 (1) evaluation of research and investigations relating to 18.24 the effects on land, water, and air resources of large electric 18.25 power generating plants and high voltage transmission line 18.26 routes and the effects of water and air discharges and electric 18.27 fields resulting from such facilities on public health and 18.28 welfare, vegetation, animals, materials, and aesthetic values, 18.29 including base line studies, predictive modeling, and monitoring 18.30 of the water and air mass at proposed and operating sites and 18.31 routes, evaluation of new or improved methods for minimizing 18.32 adverse impacts of water and air discharges and other matters 18.33 pertaining to the effects of power plants on the water and air 18.34 environment; 18.35 (2) environmental evaluation of sites and routes proposed 18.36 for future development and expansion and their relationship to 19.1 the land, water, air, and human resources of the state; 19.2 (3) evaluation of the effects of new electric power 19.3 generation and transmission technologies and systems related to 19.4 power plants designed to minimize adverse environmental effects; 19.5 (4) evaluation of the potential for beneficial uses of 19.6 waste energy from proposed large electric power generating 19.7 plants; 19.8 (5) analysis of the direct and indirect economic impact of 19.9 proposed sites and routes including, but not limited to, 19.10 productive agricultural land lost or impaired; 19.11 (6) evaluation of adverse direct and indirect environmental 19.12 effectswhichthat cannot be avoided should the proposed site 19.13 and route be accepted; 19.14 (7) evaluation of alternatives to the applicant's proposed 19.15 site or route proposed pursuant to subdivisions 1 and 2; 19.16 (8) evaluation of potential routeswhichthat would use or 19.17 parallel existing railroad and highway rights-of-way; 19.18 (9) evaluation of governmental survey lines and other 19.19 natural division lines of agricultural land so as to minimize 19.20 interference with agricultural operations; 19.21 (10) evaluation of the future needs for additional high 19.22 voltage transmission lines in the same general area as any 19.23 proposed route, and the advisability of ordering the 19.24 construction of structures capable of expansion in transmission 19.25 capacity through multiple circuiting or design modifications; 19.26 (11) evaluation of irreversible and irretrievable 19.27 commitments of resources should the proposed site or route be 19.28 approved; and 19.29 (12)wherewhen appropriate, consideration of problems 19.30 raised by other state and federal agencies and local entities. 19.31(13)(b) If the board's rules are substantially similar to 19.32 existingrules andregulations of a federal agency to which the 19.33 utility in the state is subject, the federalrules and19.34 regulationsshallmust be applied by the board. 19.35(14)(c) No site or routeshallmay be designatedwhich19.36violatesif to do so would violate state agency rules. 20.1 Sec. 11. Minnesota Statutes 2000, section 116C.57, is 20.2 amended by adding a subdivision to read: 20.3 Subd. 7. [TIMING.] The board shall make a final decision 20.4 on an application within 60 days after receipt of the report of 20.5 the administrative law judge. A final decision on the request 20.6 for a site permit or route permit shall be made within one year 20.7 after the chair's determination that an application is 20.8 complete. The time for the final decision may be extended for 20.9 up to 90 days for good cause and if all parties agree. 20.10 Sec. 12. Minnesota Statutes 2000, section 116C.57, is 20.11 amended by adding a subdivision to read: 20.12 Subd. 8. [FINAL DECISION.] (a) A site permit may not be 20.13 issued in violation of the site selection standards and criteria 20.14 established in this section and in rules adopted by the board. 20.15 The board shall indicate the reasons for any refusal and 20.16 indicate changes in size or type of facility necessary to allow 20.17 site designation. When the board designates a site, it shall 20.18 issue a site permit to the applicant with any appropriate 20.19 conditions. The board shall publish a notice of its decision in 20.20 the State Register within 30 days of issuing the site permit. 20.21 (b) A route permit may not be issued in violation of the 20.22 route selection standards and criteria established in this 20.23 section and in rules adopted by the board. When the route is 20.24 designated, the permit issued for the construction of the 20.25 facility must specify the type, design, routing, right-of-way 20.26 preparation, and facility construction deemed necessary and any 20.27 other appropriate conditions. The board may order the 20.28 construction of high voltage transmission line facilities that 20.29 are capable of expansion in transmission capacity through 20.30 multiple circuiting or design modifications. The board shall 20.31 publish a notice of its decision in the State Register within 30 20.32 days of issuing the permit. 20.33 Sec. 13. [116C.575] [ALTERNATIVE REVIEW OF APPLICATIONS.] 20.34 Subdivision 1. [ALTERNATIVE REVIEW.] An applicant who 20.35 seeks a site permit or route permit for one of the projects 20.36 identified in this section may petition the board to be allowed 21.1 to follow the procedures in this section rather than the 21.2 procedures in section 116C.57. The board shall grant the 21.3 petition within 30 days unless the board finds good cause for 21.4 denial. 21.5 Subd. 2. [APPLICABLE PROJECTS.] The requirements and 21.6 procedures in this section may apply to the following projects: 21.7 (1) large electric power generating plants with a capacity 21.8 of between 50 and 80 megawatts regardless of fuel; 21.9 (2) large electric power generating plants powered by 21.10 natural gas as its primary fuel; 21.11 (3) projects to retrofit or repower an existing large 21.12 electric power generating plant to one burning primarily natural 21.13 gas or other similar clean fuel; 21.14 (4) any natural gas peaking facility designed for or 21.15 capable of storing on a single site more than 100,000 gallons of 21.16 liquefied natural gas or synthetic gas; 21.17 (5) high voltage transmission lines of between 100 and 200 21.18 kilovolts; 21.19 (6) high voltage transmission lines in excess of 200 21.20 kilovolts less than five miles in length in Minnesota; and 21.21 (7) high voltage transmission lines in excess of 200 21.22 kilovolts if at least 80 percent of the distance of the line in 21.23 Minnesota will be located parallel or along existing high 21.24 voltage transmission line right-of-way. 21.25 Subd. 3. [APPLICATION.] The applicant for a site 21.26 certificate or route permit for any of the projects listed in 21.27 subdivision 2 who chooses to follow these procedures shall 21.28 submit information the board may require, but the applicant is 21.29 not required to propose a second site or route for the project. 21.30 The applicant shall identify in the application any other sites 21.31 or routes that were rejected by the applicant and the board may 21.32 identify additional sites or routes to consider during the 21.33 processing of the application. The chair of the board shall 21.34 determine whether an application is complete and advise the 21.35 applicant of any deficiencies. 21.36 Subd. 4. [NOTICE OF APPLICATION.] On submitting an 22.1 application under this section, the applicant shall provide the 22.2 same notice as required by section 116C.57, subdivision 4. 22.3 Subd. 5. [ENVIRONMENTAL REVIEW.] For the projects 22.4 identified in subdivision 2 and following these procedures, the 22.5 board shall prepare an environmental assessment worksheet. The 22.6 board shall include as part of the environmental assessment 22.7 worksheet alternative sites or routes identified by the board 22.8 and shall address mitigating measures for all of the sites or 22.9 routes considered. The environmental assessment worksheet is 22.10 the only state environmental review document required to be 22.11 prepared on the project. 22.12 Subd. 6. [PUBLIC MEETING.] The board and the independent 22.13 reliability administrator shall hold a joint public meeting in 22.14 the area where the facility is proposed to be located. The 22.15 board shall give notice of the public meeting in the same manner 22.16 as notice for a public hearing. The board shall provide 22.17 opportunity at the public meeting for any person to present 22.18 comments and to ask questions of the applicant and board staff. 22.19 The board shall also afford interested persons an opportunity to 22.20 submit written comments into the record. 22.21 Subd. 7. [TIMING.] The board shall make a final decision 22.22 on an application within 60 days after completion of the public 22.23 meeting. A final decision on the request for a site permit or 22.24 route permit under this section must be made within six months 22.25 after the chair's determination that an application is 22.26 complete. The time for the final decision may be extended for 22.27 up to 45 days for good cause and if all parties agree. 22.28 Subd. 8. [CONSIDERATIONS.] The considerations in section 22.29 116C.57, subdivision 4, apply to any projects subject to this 22.30 section. 22.31 Subd. 9. [FINAL DECISION.] (a) A site permit may not be 22.32 issued in violation of the site selection standards and criteria 22.33 established in this section and in rules adopted by the board. 22.34 The board shall indicate the reasons for any refusal and 22.35 indicate changes in size or type of facility necessary to allow 22.36 site designation. When the board designates a site, it shall 23.1 issue a site permit to the applicant with any appropriate 23.2 conditions. The board shall publish a notice of its decision in 23.3 the State Register within 30 days of issuance of the site permit. 23.4 (b) A route designation may not be made in violation of the 23.5 route selection standards and criteria established in this 23.6 section and in rules adopted by the board. When the board 23.7 designates a route, it shall issue a permit for the construction 23.8 of a high voltage transmission line specifying the type, design, 23.9 routing, right-of-way preparation, and facility construction it 23.10 deems necessary and with any other appropriate conditions. The 23.11 board may order the construction of high voltage transmission 23.12 line facilities that are capable of expansion in transmission 23.13 capacity through multiple circuiting or design modifications. 23.14 The board shall publish a notice of its decision in the State 23.15 Register within 30 days of issuance of the permit. 23.16 Sec. 14. [116C.576] [EMERGENCY PERMIT.] 23.17 (a) Any utility whose electric power system requires the 23.18 immediate construction of a large electric power generating 23.19 plant or high voltage transmission line due to a major 23.20 unforeseen event may apply to the board for an emergency permit 23.21 after providing notice in writing to the public utilities 23.22 commission of the major unforeseen event and the need for 23.23 immediate construction. The permit must be issued in a timely 23.24 manner, no later than 195 days after the board's acceptance of 23.25 the application and upon a finding by the board that (1) a 23.26 demonstrable emergency exists, (2) the emergency requires 23.27 immediate construction, and (3) adherence to the procedures and 23.28 time schedules specified in section 116C.57 would jeopardize the 23.29 utility's electric power system or would jeopardize the 23.30 utility's ability to meet the electric needs of its customers in 23.31 an orderly and timely manner. 23.32 (b) A public hearing to determine if an emergency exists 23.33 must be held within 90 days of the application. The board, 23.34 after notice and hearing, shall adopt rules specifying the 23.35 criteria for emergency certification. 23.36 Sec. 15. Minnesota Statutes 2000, section 116C.58, is 24.1 amended to read: 24.2 116C.58 [PUBLIC HEARINGS; NOTICEANNUAL HEARING.] 24.3 The board shall hold an annual public hearing at a time and 24.4 place prescribed by rule in order to afford interested persons 24.5 an opportunity to be heard regardingits inventory of study24.6areas and any other aspects of the board's activities and duties24.7or policies specified in sections 116C.51 to 116C.69. The board24.8shall hold at least one public hearing in each county where a24.9site or route is being considered for designation pursuant to24.10section 116C.57. Notice and agenda of public hearings and24.11public meetings of the board held in each county shall be given24.12by the board at least ten days in advance but no earlier than 4524.13days prior to such hearings or meetings. Notice shall be by24.14publication in a legal newspaper of general circulation in the24.15county in which the public hearing or public meeting is to be24.16held and by certified mailed notice to chief executives of the24.17regional development commissions, counties, organized towns and24.18the incorporated municipalities in which a site or route is24.19proposed. All hearings held for designating a site or route or24.20for exempting a route shall be conducted by an administrative24.21law judge from the office of administrative hearings pursuant to24.22the contested case procedures of chapter 14. Any person may24.23appear at the hearings and present testimony and exhibits and24.24may question witnesses without the necessity of intervening as a24.25formal party to the proceedings.any matters relating to the 24.26 siting of large electric generating power plants and routing of 24.27 high voltage transmission lines. At the meeting, the board 24.28 shall advise the public of the permits issued by the board in 24.29 the past year. The board shall provide at least ten days' 24.30 notice, but no more than 45 days' notice, of the annual meeting 24.31 by mailing notice to those persons who have requested notice and 24.32 by publication in the board's "EQB Monitor." 24.33 Sec. 16. Minnesota Statutes 2000, section 116C.59, 24.34 subdivision 1, is amended to read: 24.35 Subdivision 1. [ADVISORY TASK FORCELOCAL PLANNING 24.36 COMMISSIONS.] The boardmay appoint one or more advisory task25.1forcesshall confer with affected local planning commissions to 25.2 assist it in carrying out its duties.Task forces appointed to25.3evaluate sites or routes considered for designation shall be25.4comprised of as many persons as may be designated by the board,25.5but at least one representative from each of the following:25.6Regional development commissions, counties and municipal25.7corporations and one town board member from each county in which25.8a site or route is proposed to be located. No officer, agent,25.9or employee of a utility shall serve on an advisory task force.25.10Reimbursement for expenses incurred shall be made pursuant to25.11the rules governing state employees. The task forces expire as25.12provided in section 15.059, subdivision 6.25.13 Sec. 17. Minnesota Statutes 2000, section 116C.60, is 25.14 amended to read: 25.15 116C.60 [PUBLIC MEETINGS; TRANSCRIPT OF PROCEEDINGS; 25.16 WRITTEN RECORDS.] 25.17 Meetings of the board, including hearings,shallmust be 25.18 open to the public. Minutesshallmust be kept of board 25.19 meetings and a complete record of public hearingsshall be25.20 kept. All books, records, files, and correspondence of the 25.21 boardshallmust be available for public inspection at any 25.22 reasonable time. Thecouncil shallboard is alsobesubject to 25.23 chapter 13D. 25.24 Sec. 18. Minnesota Statutes 2000, section 216B.16, is 25.25 amended by adding a subdivision to read: 25.26 Subd. 17. [DISTRIBUTED GENERATION TARIFF.] (a) In order to 25.27 facilitate and encourage the use of distributed generation, each 25.28 public utility providing electric service at retail shall file a 25.29 distributed generation tariff for commission approval or 25.30 approval with modification. 25.31 (b) The commission may approve a tariff that it finds: 25.32 (1) provides for the low-cost, safe, and standardized 25.33 interconnection, consistent with sections 216B.68 to 216B.75, of 25.34 customer-owned distributed generation facilities (i) consisting 25.35 of fuel cells and microturbines fueled by natural gas, renewable 25.36 fuels, or other similarly clean fuels, by wind, or by 26.1 photo-voltaics; (ii) with a capacity of two megawatts or less; 26.2 (iii) owned by small-business or residential customers; and (iv) 26.3 constructed on-site; 26.4 (2) encourages and compensates for the addition of 26.5 distributed generation power resources while reducing the cost 26.6 to the utility's customers for energy, capacity, transmission 26.7 and distribution; 26.8 (3) minimizes and avoids tariff-related increases in the 26.9 rates of customers not taking service under the distributed 26.10 generation tariff; and 26.11 (4) allows for reasonable terms and conditions, consistent 26.12 with the cost and operating characteristics of the various 26.13 technologies, so that the utility can reasonably rely upon the 26.14 equipment to be operational when called upon. 26.15 (c) The commission may develop financial incentives based 26.16 on a utility's performance in encouraging residential and small 26.17 business customers to participate in on-site generation. 26.18 Sec. 19. Minnesota Statutes 2000, section 216B.2421, 26.19 subdivision 2, is amended to read: 26.20 Subd. 2. [LARGE ENERGY FACILITY.] "Large energy facility" 26.21 means: 26.22 (1) any electric power generating plant or combination of 26.23 plants at a single site with a combined capacity of 80,000 26.24 kilowatts or more, or any facility of 50,000 kilowatts or more26.25which requires oil, natural gas, or natural gas liquids as a26.26fuel and for which an installation permit has not been applied26.27for by May 19, 1977 pursuant to Minn. Reg. APC 3(a); 26.28 (2) any high voltage transmission line with a capacity of 26.29200100 kilovolts or more and (i) with more than50ten miles 26.30 of its length in Minnesota, or (ii) any of its length in 26.31 Minnesota and that crosses the state line;or, any high voltage26.32transmission line with a capacity of 300 kilovolts or more with26.33more than 25 miles of its length in Minnesota;26.34 (3) any pipeline greater than six inches in diameter and 26.35 having more than 50 miles of its length in Minnesota used for 26.36 the transportation of coal, crude petroleum or petroleum fuels 27.1 or oil or their derivatives; 27.2 (4) any pipeline for transporting natural or synthetic gas 27.3 at pressures in excess of 200 pounds per square inch with more 27.4 than 50 miles of its length in Minnesota; 27.5 (5) any facility designed for or capable of storing on a 27.6 single site more than 100,000 gallons of liquefied natural gas 27.7 or synthetic gas; 27.8 (6) any underground gas storage facility requiring permit 27.9 pursuant to section 103I.681; 27.10 (7) any nuclear fuel processing or nuclear waste storage or 27.11 disposal facility; and 27.12 (8) any facility intended to convert any material into any 27.13 other combustible fuel and having the capacity to process in 27.14 excess of 75 tons of the material per hour. 27.15 Sec. 20. Minnesota Statutes 2000, section 216B.2421, is 27.16 amended by adding a subdivision to read: 27.17 Subd. 4. [MODIFYING EXISTING LARGE ENERGY FACILITY.] 27.18 Refurbishing or upgrading an existing large energy facility 27.19 through the replacement or addition of facility components does 27.20 not require a certificate of need under section 216B.243, unless 27.21 the changes lead to (1) a capacity increase of more than 100 27.22 megawatts, or ten percent of existing capacity, whichever is 27.23 greater, or (2) operation at more than 50 percent higher voltage. 27.24 Sec. 21. Minnesota Statutes 2000, section 216B.243, 27.25 subdivision 2, is amended to read: 27.26 Subd. 2. [CERTIFICATE REQUIRED.] (a) Except as provided in 27.27 paragraph (b), no large energy facilityshallmay be sited or 27.28 constructed in Minnesota without the issuance of a certificate 27.29 of need by the commission pursuant to sections 216C.05 to 27.30 216C.30 and this section and consistent with the criteria for 27.31 assessment of need. 27.32 (b) Notwithstanding paragraph (a), a large energy facility 27.33 that is a generation plant or a natural gas peaking facility not 27.34 owned by a public or municipal utility or cooperative electric 27.35 association and that is not to be included in the utility's or 27.36 association's rate base does not need a certificate of need 28.1 under this section. 28.2 Sec. 22. Minnesota Statutes 2000, section 216B.243, is 28.3 amended by adding a subdivision to read: 28.4 Subd. 2a. [PUBLIC PURPOSE DESIGNATION.] (a) When filing 28.5 for a certificate of need under this section, an applicant may 28.6 also petition the commission to designate the proposed large 28.7 energy facility a public purpose project. The commission shall 28.8 approve or reject the petition at the same time the commission 28.9 renders its decision under subdivision 5. Notwithstanding 28.10 section 116C.63 or any other law to the contrary, eminent domain 28.11 authority may not be used in constructing a large energy 28.12 facility unless the commission designates the facility a public 28.13 purpose project. The value paid for property in the exercise of 28.14 eminent domain authority may be structured so as to provide for 28.15 the payment of a portion of the revenue derived from the large 28.16 energy facility over a period of years, rather than a lump sum 28.17 payment at the time the property is taken. 28.18 (b) In deciding whether to designate a proposed large 28.19 energy facility as a public purpose project, the commission 28.20 shall consider whether the proposed facility: 28.21 (1) remedies a condition, or set of conditions, that 28.22 materially limit the adequacy of electric supply, efficiency of 28.23 electric service, or reliability of electric service to 28.24 Minnesota consumers; 28.25 (2) was identified as a critical need by the relevant 28.26 regional energy infrastructure planning group; 28.27 (3) is consistent with all relevant state goals and 28.28 strategies approved by the legislature under section 216B.017; 28.29 and 28.30 (4) is otherwise in the public interest. 28.31 Sec. 23. Minnesota Statutes 2000, section 216B.243, 28.32 subdivision 3, is amended to read: 28.33 Subd. 3. [SHOWING REQUIRED FOR CONSTRUCTION.]No(a) A 28.34 proposed large energy facilityshallmay not be certified for 28.35 construction unless the applicantcan show that demand for28.36electricity cannot be met more cost-effectively through energy29.1conservation and load-management measures and unless the29.2applicanthasotherwisejustified its need. 29.3 (b) In assessing need, the commission shall evaluate: 29.4 (1) the accuracy of the long-range energy demand forecasts 29.5 on which the necessity for the facility is based; 29.6 (2)the effect of existing or possible energy conservation29.7programs under sections 216C.05 to 216C.30 and this section or29.8other federal or state legislation on long-term energy demand;29.9(3)the relationship of the proposed facility to overall 29.10 state and regional energy needs,as described in the most recent29.11state energy policy and conservation report prepared under29.12section 216C.18including consideration of (i) the most recent 29.13 state energy security blueprint under section 216B.015, (ii) the 29.14 most recent relevant regional energy infrastructure planning 29.15 group report under section 216B.019, and (iii) information from 29.16 federal and regional reliability organizations, regional 29.17 transmission organizations, and other relevant sources; 29.18(4) promotional activities that may have given rise to the29.19demand for this facility;29.20(5) socially beneficial uses of the output(3) 29.21 environmental and socioeconomic benefits of this facility, 29.22 including its uses to protect or enhance environmental quality, 29.23 to increase reliability of energy supply in Minnesota and the 29.24 region, and to induce future development; 29.25(6) the effects of the facility in inducing future29.26development;29.27(7)(4) possible alternatives for satisfying the energy 29.28 demand or transmission needs including but not limited to 29.29 potential for increased efficiency and upgrading of existing 29.30 energy generation and transmission facilities, load management 29.31 programs, and distributed generation; 29.32(8)(5) the policies, rules, and regulations of other state 29.33 and federal agencies and local governments;and29.34(9) any(6) feasiblecombination ofenergy conservation 29.35 improvements, required under section 216B.241, sections 216C.05 29.36 to 216C.30, or other available conservation programs that can (i) 30.1 reasonably replace a significant part or all of the energy to be 30.2 provided by the proposed facility, and (ii) compete with it 30.3 economically and in terms of reliability; and 30.4 (7) whether the proposed large energy facility was 30.5 recommended for construction by the relevant regional energy 30.6 infrastructure planning group. 30.7 Sec. 24. Minnesota Statutes 2000, section 216B.243, 30.8 subdivision 4, is amended to read: 30.9 Subd. 4. [APPLICATION FOR CERTIFICATE; HEARING.] Any 30.10 person proposing to construct a large energy facility shall 30.11 apply for a certificate of need prior to construction of the 30.12 facility. The application shall be on forms and in a manner 30.13 established by the commission. In reviewing each application 30.14 the commission shall hold at least one public hearing pursuant 30.15 to chapter 14. The public hearing shall be held at a location 30.16 and hour reasonably calculated to be convenient for the public. 30.17 An objective of the public hearing shall be to obtain public 30.18 opinion on the necessity of granting a certificate of need. The 30.19 commission shall designate a commission employee whose duty 30.20 shall be to facilitate citizen participation in the hearing 30.21 process. If the commission and the environmental quality board 30.22 determine that a joint hearing on siting and need under this 30.23 subdivision and section 116C.57, subdivision 2d, is feasible, 30.24 more efficient, and may further the public interest, a joint 30.25 hearing under those subdivisions may be held. 30.26 Sec. 25. [INSTRUCTION TO REVISOR.] 30.27 The revisor of statutes shall renumber Minnesota Statutes, 30.28 section 116C.57, subdivision 6, as section 116C.57, subdivision 30.29 9. 30.30 Sec. 26. [REPEALER.] 30.31 Minnesota Statutes 2000, sections 116C.55; 116C.57, 30.32 subdivisions 3, 5, and 5a; and 116C.67, are repealed. 30.33 Sec. 27. [EFFECTIVE DATES.] 30.34 This article is effective the day following final 30.35 enactment, except that those provisions referring or relating to 30.36 article 1, section 2 or 3, the independent reliability 31.1 administrator or the state reliability plan, are effective July 31.2 1, 2002. Section 2 does not apply to any proposal for a 31.3 transmission line between 100 and 200 kilovolts that is pending 31.4 before a local unit of government as of February 1, 2001. 31.5 ARTICLE 3 31.6 REGULATORY FLEXIBILITY 31.7 Section 1. Minnesota Statutes 2000, section 216B.16, 31.8 subdivision 7, is amended to read: 31.9 Subd. 7. [ENERGY COST ADJUSTMENT.] (a) Notwithstanding any 31.10 other provision of this chapter, the commission may permit a 31.11 public utility to file rate schedules containing provisions for 31.12 the automatic adjustment of charges for public utility service 31.13 in direct relation to changes in: (1) federally regulated 31.14 wholesale rates for energy delivered through interstate 31.15 facilities; (2) direct costs for natural gas delivered; or (3) 31.16 costs for fuel used in generation of electricity or the 31.17 manufacture of gas. 31.18 (b) In reviewing utility fuel purchases under this or any 31.19 other provision, the commission shall allow and encourage a 31.20 utility to have a combination of measures to manage price 31.21 volatility and risk, including but not limited to having an 31.22 appropriate share of the utility's supply come from long-term 31.23 and medium-term contracts, in order to minimize consumer 31.24 exposure to fuel price volatility. 31.25 Sec. 2. [216B.169] [RENEWABLE AND HIGH EFFICIENCY ENERGY 31.26 RATE OPTIONS.] 31.27 (a) Each public utility, cooperative association, and 31.28 municipal utility shall offer its customers and shall advertise 31.29 the offer at least annually one or more options that allow a 31.30 customer to determine that a certain amount of the electricity 31.31 generated or purchased on behalf of the customer is (1) 31.32 renewable energy as defined in section 216B.2422, subdivision 1, 31.33 paragraph (c), or (2) high-efficiency, low-emissions, 31.34 distributed generation such as fuel cells and microturbines 31.35 fueled by a renewable fuel. 31.36 (b) Each public utility shall file an implementation plan 32.1 within 90 days of the effective date of this section to 32.2 implement paragraph (a). 32.3 (c) Rates charged to customers must be calculated using the 32.4 utility's or association's cost of acquiring the energy for the 32.5 customer and must be (1) the difference between the cost of 32.6 generating or purchasing the renewable energy and the cost of 32.7 generating or purchasing the same amount of nonrenewable energy; 32.8 and (2) distributed on a per kilowatt-hour basis among all 32.9 customers who choose to participate in the program. 32.10 Implementation of these rate options may reflect a reasonable 32.11 amount of lead time necessary to arrange acquisition of the 32.12 energy. 32.13 (d) If a utility is not able to arrange an adequate supply 32.14 of renewable or high-efficiency energy to meet its customers' 32.15 demand under this section, the utility must file a report with 32.16 the commission detailing its efforts and reasons for its failure. 32.17 (e) The commission, by order, may establish a program for 32.18 tradeable credits for renewable energy under this section. 32.19 Sec. 3. Minnesota Statutes 2000, section 216B.241, 32.20 subdivision 1, is amended to read: 32.21 Subdivision 1. [DEFINITIONS.] For purposes of this section 32.22 andsectionsections 216B.16, subdivision 6b, and 216B.2411, the 32.23 terms defined in this subdivision have the meanings given them. 32.24 (a) "Commission" means the public utilities commission. 32.25 (b) "Commissioner" means the commissioner ofpublic service32.26 commerce. 32.27 (c) "Customer facility" means all buildings, structures, 32.28 equipment, and installations at a single site. 32.29 (d) "Department" means the department ofpublic32.30servicecommerce. 32.31 (e) "Energy conservation improvement" means the purchase or 32.32 installation of a device, method, material, or project that: 32.33 (1) reduces consumption of or increases efficiency in the 32.34 use of electricity or natural gas, including but not limited to 32.35 insulation and ventilation, storm or thermal doors or windows, 32.36 caulking and weatherstripping, furnace efficiency modifications, 33.1 thermostat or lighting controls, awnings, or systems to turn off 33.2 or vary the delivery of energy; 33.3 (2) either (i) creates, converts, or actively uses energy 33.4 from renewable sources such as solar, wind, and biomass, or (ii) 33.5 recovers energy for reuse, from air or water or other similar 33.6 material, provided that the device or method conforms with 33.7 national or state performance and quality standards whenever 33.8 applicable; 33.9 (3) seeks to provide energy savings through reclamation or 33.10 recycling and that is used as part of the infrastructure of an 33.11 electric generation, transmission, or distribution system within 33.12 the state or a natural gas distribution system within the state; 33.13 or 33.14 (4) provides research or development of new means of 33.15 increasing energy efficiency or conserving energy or research or 33.16 development of improvement of existing means of increasing 33.17 energy efficiency or conserving energy. 33.18 For a public utility, municipal utility, or cooperative 33.19 electric association that elects to be governed by section 33.20 216B.2411, the difference between the amount required to be 33.21 spent under that section and the amount that the utility would 33.22 have spent under this section may be used (i) for purposes of 33.23 making grants for the development of renewable energy 33.24 facilities, such as those utilizing agricultural wastes as 33.25 biomass fuel and methane digester facilities associated with 33.26 livestock feedlots for the production of energy, and requiring 33.27 the grants, to the extent feasible, to be coordinated with loans 33.28 under the shared savings loan program established in section 33.29 17.115, and (ii) for the purchase or installation of a device, 33.30 method, or project that increases a customer's ability to 33.31 control the amount and scheduling of energy purchased from a 33.32 utility, resulting in an overall decrease in energy consumption, 33.33 through the innovative installation of high-efficiency on-site 33.34 generation such as fuel cells or microturbines in combination 33.35 with other conservation initiatives, or through other 33.36 technologies to allow customers to manage their own load. 34.1 (f) "Investments and expenses of a public utility" includes 34.2 the investments and expenses incurred by a public utility in 34.3 connection with an energy conservation improvement, including 34.4 but not limited to: 34.5 (1) the differential in interest cost between the market 34.6 rate and the rate charged on a no-interest or below-market 34.7 interest loan made by a public utility to a customer for the 34.8 purchase or installation of an energy conservation improvement; 34.9 (2) the difference between the utility's cost of purchase 34.10 or installation of energy conservation improvements and any 34.11 price charged by a public utility to a customer for such 34.12 improvements. 34.13 (g) "Large electric customer facility" means a customer 34.14 facility that imposes a peak electrical demand on an electric 34.15 utility's system of not less than20,00010,000 kilowatts, 34.16 measured in the same way as the utility that serves the customer 34.17 facility measures electrical demand for billing purposes, and 34.18 for which electric services are provided at retail on a single 34.19 bill by a utility operating in the state. 34.20 Sec. 4. Minnesota Statutes 2000, section 216B.241, 34.21 subdivision 1a, is amended to read: 34.22 Subd. 1a. [INVESTMENT, EXPENDITURE, AND CONTRIBUTION; 34.23 PUBLIC UTILITY.] (a) For purposes of this subdivision and 34.24 subdivision 2, "public utility" has the meaning given it in 34.25 section 216B.02, subdivision 4. Each public utility shall spend 34.26 and invest for energy conservation improvements under this 34.27 subdivision and subdivision 2 the following amounts: 34.28 (1) for a utility that furnishes gas service, 0.5 percent 34.29 of its gross operating revenues from service provided in the 34.30 state; 34.31 (2) for a utility that furnishes electric service, 1.5 34.32 percent of its gross operating revenues from service provided in 34.33 the state; and 34.34 (3) for a utility that furnishes electric service and that 34.35 operates a nuclear-powered electric generating plant within the 34.36 state, two percent of its gross operating revenues from service 35.1 provided in the state. 35.2 For purposes of this paragraph (a), "gross operating revenues" 35.3 do not include revenues from large electric customer facilities 35.4 exempted by the commissionerof the department of public service35.5 pursuant to paragraph (b). 35.6 (b) The owner of a large electric customer facility may 35.7 petition thecommissioner of the department of public35.8servicecommission to exempt both electric and gas utilities 35.9 serving the large energy customer facility from the investment 35.10 and expenditure requirements of paragraph (a) with respect to 35.11 retail revenues attributable to the facility. At a minimum, the 35.12 petition must be supported by evidence relating to international 35.13 or domestic competitive or economic pressures on the customer 35.14 and a showing by the customer of reasonable efforts to identify, 35.15 evaluate, and implement cost-effective conservation improvements 35.16 at the facility. The commission may grant the petition, 35.17 exempting both electric and gas utilities serving the large 35.18 energy customer facility from the investment and expenditure 35.19 requirements of paragraph (a) with respect to any percent of the 35.20 retail revenues attributable to the facility the commission 35.21 deems reasonable, upon a showing by the customer that it has 35.22 implemented all energy conservation improvements with a 35.23 seven-year payback or less, verified by a registered engineer or 35.24 other individual as authorized by the commission. If a petition 35.25 is filed on or before October 1 of any year, the order of the 35.26commissionercommission to exempt revenues attributable to the 35.27 facility can be effective no earlier than January 1 of the 35.28 following year. Thecommissionercommission shall not grant an 35.29 exemption if thecommissionercommission determines that 35.30 granting the exemption is contrary to the public interest. 35.31 Thecommissionercommission may, after investigation, rescind 35.32 any exemption granted under this paragraph upon a determination 35.33 that cost-effective energy conservation improvements are 35.34 available at the large electric customer facility. For the 35.35 purposes of this paragraph, "cost-effective" means that the 35.36 projected total cost of the energy conservation improvement at 36.1 the large electric customer facility is less than the projected 36.2 present value of the energy and demand savings resulting from 36.3 the energy conservation improvement. For the purposes of 36.4 investigations by thecommissionercommission under this 36.5 paragraph, the owner of any large electric customer facility 36.6 shall, upon request, provide thecommissionercommission with 36.7 updated information comparable to that originally supplied in or 36.8 with the owner's original petition under this paragraph. 36.9 (c)The commissioner may require investments or spending36.10greater than the amounts required under this subdivision for a36.11public utility whose most recent advance forecast required under36.12section 216B.2422 or 216C.17 projects a peak demand deficit of36.13100 megawatts or greater within five years under mid-range36.14forecast assumptions.36.15(d)A public utility or owner of a large electric customer 36.16 facility may appeal a decision of the commissioner under 36.17 paragraph (b)or (c)to the commission under subdivision 2. In 36.18 reviewing a decision of the commissioner under paragraph (b)or36.19(c), the commission shall rescind the decision if it findsthat36.20 therequired investments or spending will:36.21(1) not result in cost-effective energy conservation36.22improvements; or36.23(2) otherwisedecision is notbein the public interest. 36.24(e) Each utility shall determine what portion of the amount36.25it sets aside for conservation improvement will be used for36.26conservation improvements under subdivision 2 and what portion36.27it will contribute to the energy and conservation account36.28established in subdivision 2a. A public utility may propose to36.29the commissioner to designate that all or a portion of funds36.30contributed to the account established in subdivision 2a be used36.31for research and development projects. Contributions must be36.32remitted to the commissioner of public service by February 1 of36.33each year. Nothing in this subdivision prohibits a public36.34utility from spending or investing for energy conservation36.35improvement more than required in this subdivision.36.36 Sec. 5. Minnesota Statutes 2000, section 216B.241, 37.1 subdivision 1b, is amended to read: 37.2 Subd. 1b. [CONSERVATION IMPROVEMENT BY COOPERATIVE 37.3 ASSOCIATION OR MUNICIPALITY.] (a) This subdivision applies to: 37.4 (1) a cooperative electric association that generates and 37.5 transmits electricity to associations that provide electricity 37.6 at retail including a cooperative electric association not 37.7 located in this state that serves associations or others in the 37.8 state; 37.9 (2) a municipality that provides electric service to retail 37.10 customers; and 37.11 (3) a municipality with gross operating revenues in excess 37.12 of $5,000,000 from sales of natural gas to retail customers. 37.13 (b) Each cooperative electric association and municipality 37.14 subject to this subdivision shall spend and invest for energy 37.15 conservation improvements under this subdivision the following 37.16 amounts: 37.17 (1) for a municipality, 0.5 percent of its gross operating 37.18 revenues from the sale of gas and one percent of its gross 37.19 operating revenues from the sale of electricity not purchased 37.20 from a public utility governed by subdivision 1a or a 37.21 cooperative electric association governed by this subdivision, 37.22 excluding gross operating revenues from electric and gas service 37.23 provided in the state to large electric customer facilities; and 37.24 (2) for a cooperative electric association, 1.5 percent of 37.25 its gross operating revenues from service provided in the state, 37.26 excluding gross operating revenues from service provided in the 37.27 state to large electric customer facilities indirectly through a 37.28 distribution cooperative electric association. 37.29 (c) Each municipality and cooperative association subject 37.30 to this subdivision shall identify and implement energy 37.31 conservation improvement spending and investments that are 37.32 appropriate for the municipality or association, except that a 37.33 municipality or association may not spend or invest for energy 37.34 conservation improvements that directly benefit a large electric 37.35 customer facility. Each municipality and cooperative electric 37.36 association subject to this subdivision may spend and invest 38.1 annually up to 15 percent of the total amount required to be 38.2 spent and invested on energy conservation improvements under 38.3 this subdivision on research and development projects that meet 38.4 the definition of energy conservation improvement in subdivision 38.5 1 and that are funded directly by the municipality or 38.6 cooperative electric association. Load management may be used 38.7 to meet the requirements of this subdivision if it reduces the 38.8 demand for or increases the efficiency of electric 38.9 services. However, each dollar spent on load management 38.10 initiatives only counts for (1) $0.65 in 2003, and (2) $0.25 in 38.11 2004 and thereafter toward the utility's or association's 38.12 conservation spending obligation under this section or section 38.13 216B.2411. A generation and transmission cooperative electric 38.14 association may include as spending and investment required 38.15 under this subdivision conservation improvement spending and 38.16 investment by cooperative electric associations that provide 38.17 electric service at retail to consumers and that are served by 38.18 the generation and transmission association. 38.19 (d) By February 1 of each year, each municipality or 38.20 cooperative shall report to the commissioner its energy 38.21 conservation improvement spending and investments with a brief 38.22 analysis of effectiveness in reducing consumption of electricity 38.23 or gas. The commissioner shall review each report and make 38.24 recommendations, where appropriate, to the municipality or 38.25 association to increase the effectiveness of conservation 38.26 improvement activities. The commissioner shall also review each 38.27 report for whether a portion of the money spent on residential 38.28 conservation improvement programs is devoted to programs that 38.29 directly address the needs of renters and low-income persons 38.30 unless an insufficient number of appropriate programs are 38.31 available. For the purposes of this subdivision and subdivision 38.32 2, "low-income" means an income of less than 185 percent of the 38.33 federal poverty level. 38.34 (e) As part of its spending for conservation improvement, a 38.35 municipality or association may contribute to the energy and 38.36 conservation account. A municipality or association may propose 39.1 to the commissioner to designate that all or a portion of funds 39.2 contributed to the account be used for research and development 39.3 projects. Any amount contributed must be remitted to the 39.4 commissioner of public service by February 1 of each year. 39.5 Sec. 6. Minnesota Statutes 2000, section 216B.241, 39.6 subdivision 2, is amended to read: 39.7 Subd. 2. [PROGRAMS.] (a) Thecommissionercommission may 39.8 by rule or order require public utilities to make investments 39.9 and expenditures in energy conservation improvements, explicitly 39.10 setting forth the interest rates, prices, and terms under which 39.11 the improvements must be offered to the customers. The required 39.12 programs must cover a two-year period.The commissioner shall39.13require at least one public utility to establish a pilot program39.14to make investments in and expenditures for energy from39.15renewable resources such as solar, wind, or biomass and shall39.16give special consideration and encouragement to programs that39.17bring about significant net savings through the use of39.18energy-efficient lighting.Thecommissionercommission shall 39.19 evaluate the program on the basis of cost-effectiveness and the 39.20 reliability of technologies employed. The rulesof the39.21departmentunder this section must provide to the extent 39.22 practicable for a free choice, by consumers participating in the 39.23 program, of the device, method, material, or project 39.24 constituting the energy conservation improvement and for a free 39.25 choice of the seller, installer, or contractor of the energy 39.26 conservation improvement, provided that the device, method, 39.27 material, or project seller, installer, or contractor is duly 39.28 licensed, certified, approved, or qualified, including under the 39.29 residential conservation services program, where applicable. 39.30 (b) Thecommissionercommission may require a utility to 39.31 make an energy conservation improvement investment or 39.32 expenditure whenever thecommissionercommission finds that the 39.33 improvement will result in energy savings at a total cost to the 39.34 utility less than the cost to the utility to produce or purchase 39.35 an equivalent amount of new supply of energy.The commissioner39.36shall nevertheless ensure that every public utility operate one40.1or more programs under periodic review by the department.Load 40.2 management may be used to meet the requirements for energy 40.3 conservation improvements under this section if it results in a 40.4 demonstrable reduction in consumption of energy. Each public 40.5 utility subject to subdivision 1a may spend and invest annually 40.6 up to 15 percent of the total amount required to be spent and 40.7 invested on energy conservation improvements under this section 40.8 by the utility on research and development projects that meet 40.9 the definition of energy conservation improvement in subdivision 40.10 1 and that are funded directly by the public utility. A public 40.11 utility may not spend for or invest in energy conservation 40.12 improvements that directly benefit a large electric customer 40.13 facility for which thecommissionercommission has issued an 40.14 exemption pursuant to subdivision 1a, paragraph (b). 40.15 Thecommissionercommission shall consider and may require a 40.16 utility to undertake a program suggested by an outside source, 40.17 including a political subdivision or a nonprofit or community 40.18 organization. 40.19 (c) No utility may make an energy conservation improvement 40.20 under this section to a building envelope unless: 40.21 (1) it is the primary supplier of energy used for either 40.22 space heating or cooling in the building; 40.23 (2) thecommissionercommission determines that special 40.24 circumstances, that would unduly restrict the availability of 40.25 conservation programs, warrant otherwise; or 40.26 (3) the utility has been awarded a contract under 40.27 subdivision 2a. 40.28 (d) Thecommissionercommission shall ensure that a portion 40.29 of the money spent on residential conservation improvement 40.30 programs is devoted to programs that directly address the needs 40.31 of renters and low-income persons unless an insufficient number 40.32 of appropriate programs are available. 40.33(e) A utility, a political subdivision, or a nonprofit or40.34community organization that has suggested a program, the40.35attorney general acting on behalf of consumers and small40.36business interests, or a utility customer that has suggested a41.1program and is not represented by the attorney general under41.2section 8.33 may petition the commission to modify or revoke a41.3department decision under this section, and the commission may41.4do so if it determines that the program is not cost-effective,41.5does not adequately address the residential conservation41.6improvement needs of low-income persons, has a long-range41.7negative effect on one or more classes of customers, or is41.8otherwise not in the public interest. The person petitioning41.9for commission review has the burden of proof. The commission41.10shall reject a petition that, on its face, fails to make a41.11reasonable argument that a program is not in the public interest.41.12 Sec. 7. Minnesota Statutes 2000, section 216B.241, 41.13 subdivision 2a, is amended to read: 41.14 Subd. 2a. [ENERGY AND CONSERVATION ACCOUNTLOW-INCOME 41.15 PERSONS.]The commissioner must deposit money contributed under41.16subdivisions 1a and 1b in the energy and conservation account in41.17the general fund. Money in the account is appropriated to the41.18department for programs designed to meet the energy conservation41.19needs of low-income persons and to make energy conservation41.20improvements in areas not adequately served under subdivision 2,41.21including research and development projects included in the41.22definition of energy conservation improvement in subdivision 1.41.23Interest on money in the account accrues to the account.Using 41.24 information collected under section 216C.02, subdivision 1, 41.25 paragraph (b), the commissioner must, to the extent possible, 41.26 allocate enough money to programs for low-income persons to 41.27 assure that their needs are being adequately addressed. The 41.28 commissioner must request the commissioner of finance to 41.29 transfer money from the account to the commissioner of children, 41.30 families, and learning for an energy conservation program for 41.31 low-income persons. In establishing programs, the commissioner 41.32 must consult political subdivisions and nonprofit and community 41.33 organizations, especially organizations engaged in providing 41.34 energy and weatherization assistance to low-income persons. At 41.35 least one program must address the need for energy conservation 41.36 improvements in areas in which a high percentage of residents 42.1 use fuel oil or propane to fuel their source of home heating. 42.2 The commissioner may contract with a political subdivision, a 42.3 nonprofit or community organization, a public utility, a 42.4 municipality, or a cooperative electric association to implement 42.5 its programs. The commissioner may provide grants to any person 42.6 to conduct research and development projects in accordance with 42.7 this section. 42.8 Sec. 8. Minnesota Statutes 2000, section 216B.241, is 42.9 amended by adding a subdivision to read: 42.10 Subd. 6. [OVERVIEW; REVIEW AND AUDIT.] (a) For 42.11 conservation activities under section 216B.2411, each public 42.12 utility shall provide the commission with a prospective overview 42.13 of the utility's planned conservation activities and the 42.14 anticipated energy savings on a biennial basis, according to a 42.15 schedule established by the commission. This overview shall 42.16 include a description of the types of activities, the consumer 42.17 sectors targeted by each, and the anticipated energy savings and 42.18 costs of each activity. This overview shall also indicate, for 42.19 each type of activity, how much additional cost-effective 42.20 conservation is likely to be achieved in subsequent years. In 42.21 addition, each public utility shall provide a report biennially 42.22 to the commission summarizing the public utility's actual 42.23 conservation activities over the previous two years, including, 42.24 for each activity, the utility's costs to the utility and to 42.25 participating customers, the utility's expected total energy 42.26 savings, the number of participating customers in each customer 42.27 class and consumer sector, and the activity's potential for 42.28 realizing additional cost-effective energy savings in the future. 42.29 (b) Each public utility shall provide a report biennially 42.30 to the commission summarizing the public utility's conservation 42.31 activities and energy savings resulting from those activities 42.32 under either this section or section 216B.2411. The public 42.33 utility shall include in the report the results of an 42.34 independent audit performed by the department or an auditor with 42.35 experience in the provision of energy conservation and energy 42.36 efficiency services approved by the commission. The commission 43.1 shall issue a report comparing the overall effectiveness of the 43.2 conservation programs in overall cost, success in reducing 43.3 overall energy use, and energy saved per dollar spent. 43.4 (c) The audit provided under paragraph (b) shall evaluate 43.5 whether the public utility has implemented cost-effective energy 43.6 conservation programs. In making this evaluation, the audit 43.7 shall consider whether the public utility's programs (1) fairly 43.8 address each of the utility's consumer classes and market 43.9 sectors, (2) use accurate data in calculating costs and energy 43.10 savings, and (3) indicate an adequate commitment to implementing 43.11 cost-effective conservation programs. Up to five percent of a 43.12 utility's conservation spending obligation under this section or 43.13 section 216B.2411 may be used for program pre-evaluation, 43.14 research and testing, monitoring, and program evaluation. 43.15 (d) Following two or more negative evaluations under 43.16 paragraph (b), the commission may determine that a public 43.17 utility is not implementing adequate energy conservation 43.18 programs under section 216B.2411. In that event, the commission 43.19 may order the utility or association to commit an appropriate 43.20 amount of its conservation spending obligations under those 43.21 sections to providing conservation programs under section 43.22 216B.241. 43.23 Sec. 9. Minnesota Statutes 2000, section 216B.241, is 43.24 amended by adding a subdivision to read: 43.25 Subd. 7. [ADDITIONAL CONSERVATION SPENDING.] (a) Nothing 43.26 in this section or section 216B.2411 prohibits any energy 43.27 utility from spending or investing more for energy conservation 43.28 improvements than is required in those sections. 43.29 (b) The commission may require a public utility to invest 43.30 or spend more than is required under this section or section 43.31 216B.2411 if the commission finds that additional investments 43.32 would be cost effective, and the utility's most recent forecast 43.33 projects a significant peak demand deficit. 43.34 Sec. 10. [216B.2411] [CONSERVATION INVESTMENT PROGRAM.] 43.35 Subdivision 1. [DEFINITIONS.] The definitions in section 43.36 216B.241 apply to this section. 44.1 Subd. 2. [INVESTMENTS.] (a) A public utility, 44.2 municipality, or cooperative electric association may elect to 44.3 be governed by this section rather than section 216B.241, by 44.4 notifying the commission of its election. However, section 44.5 216B.241, subdivisions 1a, paragraph (b); 1b, paragraph (c); and 44.6 2b, apply to conservation investments made under this section. 44.7 (b) Each entity that elects to be governed by this section 44.8 shall spend and invest for energy conservation improvements the 44.9 following amounts: 44.10 (1) for a public utility that furnishes gas service, 0.75 44.11 percent of the utility's annual average gross operating revenues 44.12 over the previous five years from service provided in this 44.13 state; 44.14 (2) for a cooperative electric association that provides 44.15 electricity at retail or a public utility that furnishes 44.16 electric service, two percent of the utility's or association's 44.17 annual average gross operating revenues over the previous five 44.18 years from service provided in this state; 44.19 (3) for a utility that furnishes electric service and that 44.20 operates a nuclear-powered electric generating plant within the 44.21 state, three percent of the utility's annual average gross 44.22 operating revenues over the previous five years from service 44.23 provided in this state; and 44.24 (4) for a municipality, 0.75 percent of the utility's 44.25 annual average gross operating revenues over the previous five 44.26 years from the sale of gas and 1.5 percent of the utility's 44.27 annual average gross operating revenues over the previous five 44.28 years from the sale of electricity not purchased from a public 44.29 utility or a cooperative electric association governed by this 44.30 subdivision over its five-year conservation spending average. 44.31 For purposes of this paragraph, "gross operating revenues" do 44.32 not include revenues from large electric customer facilities 44.33 exempted by the commissioner pursuant to section 216B.241, 44.34 subdivision 1a, paragraph (b). Entities electing to be governed 44.35 by this section shall comply with section 216B.241, subdivision 44.36 6. 45.1 Sec. 11. [216B.401] [UTILITY JOINT VENTURES.] 45.2 Subdivision 1. [AUTHORIZATION.] Public utilities, 45.3 cooperative electric associations, and municipal utilities may 45.4 enter into joint ventures with one another for providing utility 45.5 services within the boundaries of each member utility's 45.6 exclusive electric service territory, as shown on the map of 45.7 service territories maintained by the department of commerce. 45.8 The terms and conditions of each proposed joint venture are 45.9 subject to ratification by the governing body of each member 45.10 municipal utility and cooperative association and, if a public 45.11 utility is a member of the proposed joint venture, the 45.12 commission. A joint venture may include the formation of a 45.13 corporate entity with an administrative and governance structure 45.14 independent of any of the member utilities. A corporate entity 45.15 formed under this section is subject to all laws and rules 45.16 applicable to the respective members of the joint venture. 45.17 Subd. 2. [POWERS.] (a) The joint venture formed under this 45.18 section, if any, has the powers, privileges, responsibilities, 45.19 and duties of the separate utilities entering into the joint 45.20 venture as the joint venture agreement may provide; except that, 45.21 upon formation of the joint venture, neither the joint venture 45.22 nor any member municipal utility has the power of eminent domain 45.23 or the authority under section 216B.44 to enlarge the service 45.24 territory served by the joint venture. 45.25 (b) These powers include, but are not limited to, the 45.26 authority to: 45.27 (1) finance, own, construct, and operate facilities 45.28 necessary for providing electric power to wholesale or retail 45.29 customers, including generation, transmission, and distribution 45.30 facilities; 45.31 (2) combine service territories, in whole or in part, upon 45.32 notice and hearing to do so with the public utilities 45.33 commission; 45.34 (3) serve customers in the two utilities' service 45.35 territories or in the combined service territory; 45.36 (4) combine, share, or employ administrative, managerial, 46.1 operational, or other staff if combining or sharing will not 46.2 degrade safety, reliability, or customer service standards; 46.3 (5) provide for joint administrative functions, such as 46.4 meter reading and billing; 46.5 (6) purchase or sell power at wholesale for resale to 46.6 customers; 46.7 (7) as required by law or rule, provide energy conservation 46.8 programs, other utility programs, public interest programs such 46.9 as cold weather shutoff protection, and energy conservation 46.10 spending programs; and 46.11 (8) participate as the parties deem necessary in providing 46.12 wholesale electric power with other municipal utilities, rural 46.13 electric cooperative utilities, investor-owned utilities, or 46.14 other entities, public or private. 46.15 Sec. 12. Minnesota Statutes 2000, section 216B.42, 46.16 subdivision 1, is amended to read: 46.17 Subdivision 1. [LARGE CUSTOMEROUTSIDE MUNICIPALITY46.18 ELECTION.] (a) Notwithstanding the establishment of assigned 46.19 service areas for electric utilities provided for in section 46.20 216B.39, customers: (i) located outside municipalities and who 46.21 require electric service with a connected load of 2,000 46.22 kilowatts or more shall not be obligated to take electric 46.23 service from the electric utility having the assigned service 46.24 area where the customer is located; or (ii) who require electric 46.25 service with a connected load of 5,000 kilowatts or more shall 46.26 not be obligated to take power supply service from the electric 46.27 utility having the assigned service area where the customer is 46.28 located, if, after notice and hearing, the commission, for a 46.29 public utility, or the governing body of a municipal utility or 46.30 cooperative electric association, so determines after 46.31 consideration of following factors: 46.32 (1) the electric service requirements of the load to be 46.33 served; 46.34 (2) the availability of an adequate power supply; 46.35 (3) the development or improvement of the electric system 46.36 of the utility seeking to provide the electric service, 47.1 including the economic factors relating thereto; 47.2 (4) the proximity of adequate facilities from which 47.3 electric service of the type required may be delivered; 47.4 (5) the preference of the customer; 47.5 (6) any and all pertinent factors affecting the ability of 47.6 the utility to furnish adequate electric service to fulfill 47.7 customers' requirements. 47.8 (b) The commission or governing body may not grant a 47.9 petition under this section unless it makes a specific finding 47.10 that there is clear and convincing evidence that doing so would 47.11 not increase costs for, or otherwise harm, any of the customers 47.12 of the utility currently serving the customer or, in the case of 47.13 a municipal power agency or a generation and transmission 47.14 cooperative electric association, any of the customers of a 47.15 member utility. If the commission or governing body grants a 47.16 petition under paragraph (a), item (ii), it shall impose all 47.17 terms and conditions on the approval that are necessary to 47.18 protect consumers, utilities, and utility systems. For the 47.19 purposes of this section, "power supply services" means the 47.20 provision of electric power supply to an end-use customer. 47.21 Power supply services includes a service relating to the usage, 47.22 purchase, or sale of electric capacity and energy, but does not 47.23 include the operation of generation facilities, or distribution 47.24 or transmission services. 47.25 Sec. 13. [CONSERVATION IMPROVEMENT PLAN; EVALUATION OF 47.26 COOPERATIVE AND MUNICIPAL PROGRAMS.] 47.27 (a) Cooperative electric association and municipal 47.28 utilities shall evaluate their energy and capacity conservation 47.29 programs, develop plans for future programs, and report their 47.30 findings and plans to the chairs of the house of representatives 47.31 and senate committees with jurisdiction over energy issues by 47.32 February 15, 2002. The evaluation shall address: 47.33 (1) whether the utility or association has implemented and 47.34 is implementing cost-effective energy conservation programs; 47.35 (2) the availability of basic conservation services and 47.36 programs to customers; 48.1 (3) methodologies that best quantify energy savings, cost 48.2 effectiveness, and the potential for cost-effective conservation 48.3 improvements; 48.4 (4) the value of local administration of conservation 48.5 programs in meeting local and statewide needs; 48.6 (5) the effect on customer bills; 48.7 (6) the role of capacity conservation in meeting utility 48.8 planning needs and state energy goals; 48.9 (7) the ability of energy conservation programs to avoid 48.10 the need for construction of generation facilities and 48.11 transmission lines; 48.12 (8) whether the utility's or association's programs address 48.13 all of the following consumer market sectors: farm, 48.14 residential, commercial, and industrial; and 48.15 (9) whether the utility's or association's programs use 48.16 accurate and auditable data in calculating costs and energy 48.17 savings. 48.18 (b) The evaluation shall develop program and performance 48.19 goals that recognize customer class, utility service area 48.20 demographics, cost of program delivery, regional economic 48.21 indicators, and utility load shape. The cost of the evaluation 48.22 may be deducted from the utility's or association's conservation 48.23 spending obligation under section 216B.241 or 216B.2411. 48.24 ARTICLE 4 48.25 INTERCONNECTION OF DISTRIBUTED RESOURCES 48.26 Section 1. [216B.68] [DEFINITIONS.] 48.27 Subdivision 1. [SCOPE.] The words and terms used in 48.28 sections 216B.68 to 216B.75 have the meanings given them in this 48.29 section. 48.30 Subd. 2. [APPLICATION FOR INTERCONNECTION AND PARALLEL 48.31 OPERATION.] "Application for interconnection and parallel 48.32 operation" with the utility system or application means a 48.33 standard form of application developed by the commissioner and 48.34 approved by the commission. 48.35 Subd. 3. [COMPANY.] "Company" means an electric utility 48.36 operating a distribution system. 49.1 Subd. 4. [ELECTRIC UTILITY.] "Electric utility" means all 49.2 electric utilities that own and operate equipment in the state 49.3 for furnishing electric service at retail. 49.4 Subd. 5. [CUSTOMER.] "Customer" means any individual 49.5 person or entity interconnected to the company's utility system 49.6 for the purpose of receiving or exporting electric power from or 49.7 to the company's utility system. 49.8 Subd. 6. [DISTRIBUTED GENERATION OR ON-SITE DISTRIBUTED 49.9 GENERATION.] "Distributed generation" or "on-site distributed 49.10 generation" means an electrical generating facility located at a 49.11 customer's point of delivery or point of common coupling of 20 49.12 megawatts or less and connected at a voltage less than or equal 49.13 to 60 kilovolts that may be connected in parallel operation to 49.14 the utility system. 49.15 Subd. 7. [FACILITY.] "Facility" means an electrical 49.16 generating installation consisting of one or more on-site 49.17 distributed generation units. The total capacity of a 49.18 facility's individual on-site distributed generation units may 49.19 exceed 20 megawatts; however, no more than 20 megawatts of a 49.20 facility's capacity will be interconnected at any point in time 49.21 at the point of common coupling under this section. 49.22 Subd. 8. [INTERCONNECTION.] "Interconnection" means the 49.23 physical connection of distributed generation to the utility 49.24 system in accordance with the requirements of this section so 49.25 that parallel operation can occur. 49.26 Subd. 9. [INTERCONNECTION AGREEMENT.] "Interconnection 49.27 agreement" means the standard form of agreement, developed and 49.28 approved by the commission. The interconnection agreement sets 49.29 forth the contractual conditions under which a company and a 49.30 customer agree that one or more facilities may be interconnected 49.31 with the company's utility system. 49.32 Subd. 10. [INVERTER-BASED PROTECTIVE 49.33 FUNCTION.] "Inverter-based protective function" means a function 49.34 of an inverter system, carried out using hardware and software, 49.35 that is designed to prevent unsafe operating conditions from 49.36 occurring before, during, and after the interconnection of an 50.1 inverter-based static power converter unit with a utility 50.2 system. For purposes of this definition, unsafe operating 50.3 conditions are conditions that, if left uncorrected, would 50.4 result in harm to personnel, damage to equipment, unacceptable 50.5 system instability, or operation outside legally established 50.6 parameters affecting the quality of service to other customers 50.7 connected to the utility system. 50.8 Subd. 11. [NETWORK SERVICE.] "Network service" means two 50.9 or more utility primary distribution feeder sources electrically 50.10 tied together on the secondary side, which is the low-voltage 50.11 side, to form one power source for one or more customers. The 50.12 service is designed to maintain service to the customers even 50.13 after the loss of one of these primary distribution feeder 50.14 sources. 50.15 Subd. 12. [PARALLEL OPERATION.] "Parallel operation" means 50.16 the operation of on-site distributed generation by a customer 50.17 while the customer is connected to the company's utility system. 50.18 Subd. 13. [POINT OF COMMON COUPLING.] "Point of common 50.19 coupling" means the point where the electrical conductors of the 50.20 company utility system are connected to the customer's 50.21 conductors and where any transfer of electric power between the 50.22 customer and the utility system takes place, such as switchgear 50.23 near the meter. 50.24 Subd. 14. [PRECERTIFIED EQUIPMENT.] "Precertified 50.25 equipment" means a specific generating and protective equipment 50.26 system or systems that have been certified as meeting the 50.27 applicable parts of this section relating to safety and 50.28 reliability by an entity approved by the commission. 50.29 Subd. 15. [PRE-INTERCONNECTION STUDY.] 50.30 "Pre-interconnection study" means a study or studies that may be 50.31 undertaken by a company in response to its receipt of a 50.32 completed application for interconnection and parallel operation 50.33 with the utility system. Pre-interconnection studies may 50.34 include, but are not limited to, service studies, coordination 50.35 studies, and utility system impact studies. 50.36 Subd. 16. [STABILIZED.] "Stabilized" means that, following 51.1 a disturbance, a company utility system has returned to the 51.2 normal range of voltage and frequency for a duration of two 51.3 minutes or a shorter time as mutually agreed to by the company 51.4 and customer. 51.5 Subd. 17. [TARIFF OR TARIFF FOR INTERCONNECTION AND 51.6 PARALLEL OPERATION OF DISTRIBUTED GENERATION.] "Tariff" or 51.7 "Tariff for interconnection and parallel operation of 51.8 distributed generation" means the commission-developed and 51.9 commission-approved tariff for interconnection and parallel 51.10 operation of distributed generation, including the application 51.11 for interconnection and parallel operation of distributed 51.12 generation and pre-interconnection study fee schedule. 51.13 Subd. 18. [UNIT.] "Unit" means a power generator. 51.14 Subd. 19. [UTILITY SYSTEM.] "Utility system" means a 51.15 company's distribution system below 60 kilovolts to which the 51.16 generation equipment is interconnected. 51.17 Sec. 2. [216B.69] [INTERCONNECTION OF ON-SITE DISTRIBUTED 51.18 GENERATION.] 51.19 Subdivision 1. [PURPOSE.] The purpose of sections 216B.68 51.20 to 216B.75 is to state the terms and conditions that govern the 51.21 interconnection and parallel operation of on-site distributed 51.22 generation to provide cost savings and reliability benefits to 51.23 customers, to establish technical requirements that will promote 51.24 the safe and reliable parallel operation of on-site distributed 51.25 generation resources, to enhance both the reliability of 51.26 electric service and economic efficiency in the production and 51.27 consumption of electricity, and to promote the use of 51.28 distributed resources in order to provide electric system 51.29 benefits during periods of capacity constraints. 51.30 Subd. 2. [OBLIGATION TO SERVE; TARIFF AND OTHER 51.31 FILINGS.] (a) No later than 270 days after the effective date of 51.32 this section, each electric utility shall file tariffs for 51.33 interconnection and parallel operation of distributed generation 51.34 in conformance with sections 216B.68 to 216B.75. The electric 51.35 utility may file a new tariff or a modification of an existing 51.36 tariff. These tariffs must ensure that backup power, 52.1 supplemental power, and maintenance power are available to all 52.2 customers and customer classes that desire this service. Any 52.3 modifications of existing tariffs or offerings of new tariffs 52.4 relating to this section must be consistent with the 52.5 commission-approved form. 52.6 (b) Concurrent with the tariff filing in this section, each 52.7 utility shall submit: 52.8 (1) a schedule detailing the charges of interconnection 52.9 studies and all supporting cost data for the charges; 52.10 (2) a standard application for interconnection and parallel 52.11 operation of distributed generation; and 52.12 (3) the interconnection agreement approved by the 52.13 commission. 52.14 Sec. 3. [216B.70] [DISCONNECTION AND RECONNECTION.] 52.15 Subdivision 1. [WHEN DISCONNECTION ALLOWED.] A utility may 52.16 disconnect a distributed generation unit from the utility system 52.17 if: 52.18 (1) the interconnection agreement with a customer expires 52.19 or terminates, in accordance with the terms of the agreement; 52.20 (2) the facility is not in compliance with the technical 52.21 requirements specified by the commissioner; 52.22 (3) continued interconnection will endanger persons or 52.23 property; or 52.24 (4) written notice is provided at least seven business days 52.25 prior to a service interruption for routine maintenance, 52.26 repairs, and utility system modifications. 52.27 Subd. 2. [INCREMENTAL DEMAND CHARGES.] During the term of 52.28 an interconnection agreement, a utility may require that a 52.29 customer disconnect its distributed generation unit or take it 52.30 off-line as a result of utility system conditions. The company 52.31 may not assess the customer incremental demand charges arising 52.32 from disconnecting the distributed generator as directed by the 52.33 company during these periods. 52.34 Sec. 4. [216B.71] [PRE-INTERCONNECTION STUDIES FOR 52.35 NONNETWORK INTERCONNECTION OF DISTRIBUTED GENERATION.] 52.36 Subdivision 1. [STUDIES.] A utility may conduct a service 53.1 study, coordination study, or utility system impact study prior 53.2 to interconnection of a distributed generation facility. When a 53.3 study is deemed necessary, the scope of the study must be based 53.4 on the characteristics of the particular distributed generation 53.5 facility to be interconnected and the utility's system at the 53.6 specific proposed location. By agreement between the utility 53.7 and its customer, a study related to interconnection of 53.8 distributed generation on the customer's premises may be 53.9 conducted by a qualified third party. 53.10 Subd. 2. [CUSTOMER FEE.] (a) A utility may not charge a 53.11 customer a fee to conduct a pre-interconnection study for 53.12 precertified distributed generation units up to 500 kilowatts 53.13 that export not more than 15 percent of the total load on a 53.14 single radial feeder and contribute not more than 25 percent of 53.15 the maximum potential short circuit current on a single radial 53.16 feeder. 53.17 (b) Prior to the interconnection of a distributed 53.18 generation facility not described in paragraph (a), a utility 53.19 may charge a customer a fee to offset its costs incurred in the 53.20 conduct of a pre-interconnection study. 53.21 Subd. 3. [WHEN UTILITY CONDUCTS STUDY.] When a utility 53.22 conducts an interconnection study, paragraphs (a) to (d) apply: 53.23 (a) The conduct of the pre-interconnection study may not 53.24 take more than four weeks. 53.25 (b) A utility shall prepare written reports of the study 53.26 findings and make them available to the customer. 53.27 (c) The study must consider both the costs incurred and the 53.28 benefits realized as a result of the interconnection of 53.29 distributed generation to the company's utility system. 53.30 (d) The utility shall provide the customer with an estimate 53.31 of the study cost before the utility initiates the study. 53.32 Sec. 5. [216B.72] [PRE-INTERCONNECTION STUDIES FOR NETWORK 53.33 INTERCONNECTION OF DISTRIBUTED GENERATION.] 53.34 Subdivision 1. [NOTICE AND FEES.] (a) Prior to charging a 53.35 pre-interconnection study fee for a network interconnection of 53.36 distributed generation, a utility shall first advise the 54.1 customer of the potential problems associated with 54.2 interconnection of distributed generation with its network 54.3 system. 54.4 (b) For potential interconnections to network systems, a 54.5 pre-interconnection study fee may not be assessed for a facility 54.6 with inverter systems under 20 kilowatts. For all other 54.7 facilities, the utility may charge the customer a fee to offset 54.8 its costs incurred in the conduct of the pre-interconnection 54.9 study. 54.10 Subd. 2. [REQUIREMENTS WHEN UTILITY CONDUCTS STUDY.] When 54.11 a utility conducts an interconnection study, paragraphs (a) to 54.12 (d) apply: 54.13 (a) The conduct of a pre-interconnection study may not take 54.14 more than four weeks. 54.15 (b) A utility shall prepare written reports of the study 54.16 findings and make them available to the customer. 54.17 (c) The study must consider both the costs incurred and the 54.18 benefits realized as a result of the interconnection of 54.19 distributed generation to the utility's system. 54.20 (d) The utility shall provide the customer with an estimate 54.21 of the study cost before the utility initiates the study. 54.22 Sec. 6. [216B.73] [EQUIPMENT PRECERTIFICATION.] (a) The 54.23 commission may approve one or more entities that shall 54.24 precertify equipment as described under this section. 54.25 (b) Testing organizations or facilities capable of 54.26 analyzing the function, control, and protective systems of 54.27 distributed generation units may request to be certified as 54.28 testing organizations. 54.29 (c) Distributed generation units that are certified to be 54.30 in compliance by an approved testing facility or organization 54.31 must be installed on a company utility system in accordance with 54.32 an approved interconnection control and protection scheme 54.33 without further review of their design by the utility. 54.34 Sec. 7. [216B.74] [TIME FOR PROCESSING APPLICATIONS FOR 54.35 INTERCONNECTION.] 54.36 (a) The interconnection of distributed generation to the 55.1 utility system must take place within the schedules described in 55.2 paragraphs (b) to (f): 55.3 (b) For a facility with precertified equipment, 55.4 interconnection must take place within four weeks of the 55.5 utility's receipt of a completed interconnection application. 55.6 (c) For facilities without precertified equipment, 55.7 connection must take place within six weeks of the utility's 55.8 receipt of a completed application. 55.9 (d) If interconnection of a particular facility will 55.10 require substantial capital upgrades to the utility system, the 55.11 company shall provide the customer an estimate of the schedule 55.12 and the customer's cost for the upgrade. If the customer 55.13 desires to proceed with the upgrade, the customer and the 55.14 company shall enter into a contract for the completion of the 55.15 upgrade. The interconnection must take place no later than two 55.16 weeks following the completion of the upgrade. The utility 55.17 shall employ best reasonable efforts to complete the system 55.18 upgrade in the shortest time reasonably practical. 55.19 (e) A utility shall use best reasonable efforts to 55.20 interconnect facilities within the time frames described in this 55.21 section. If in a particular instance, a utility determines that 55.22 it cannot interconnect a facility within the time frames stated 55.23 in this section, it must notify the applicant in writing of that 55.24 fact. The notification must identify any reasons 55.25 interconnection could not be performed in accordance with the 55.26 schedule and provide an estimated date for interconnection. 55.27 (f) Applications for interconnection and parallel operation 55.28 of distributed generation must be processed by the utility in a 55.29 nondiscriminatory manner and in the order that they are 55.30 received. It is recognized that certain applications may 55.31 require minor modifications while they are being reviewed by the 55.32 utility. These minor modifications to a pending application do 55.33 not require that it be considered incomplete and treated as a 55.34 new or separate application. 55.35 Sec. 8. [216B.75] [REPORTING REQUIREMENTS.] 55.36 (a) Each electric utility shall maintain records concerning 56.1 applications received for interconnection and parallel operation 56.2 of distributed generation. The records must include the date 56.3 each application is received, documents generated in the course 56.4 of processing each application, correspondence regarding each 56.5 application, and the final disposition of each application. 56.6 (b) By March 30 of each year, every electric utility shall 56.7 file with the commission a distributed generation 56.8 interconnection report for the preceding calendar year that 56.9 identifies each distributed generation facility interconnected 56.10 with the utility's distribution system. The report must list 56.11 the new distributed generation facilities interconnected with 56.12 the system since the previous year's report, any distributed 56.13 generation facilities no longer interconnected with the 56.14 utility's system since the previous report, the capacity of each 56.15 facility, and the feeder or other point on the company's utility 56.16 system where the facility is connected. The annual report must 56.17 also identify all applications for interconnection received 56.18 during the previous one-year period, and the disposition of the 56.19 applications. 56.20 ARTICLE 5 56.21 CONFORMING AMENDMENTS 56.22 Section 1. Minnesota Statutes 2000, section 116C.61, 56.23 subdivision 1, is amended to read: 56.24 Subdivision 1. [REGIONAL, COUNTY AND LOCAL ORDINANCES,56.25RULES, REGULATIONS;PRIMARYRESPONSIBILITY ANDREGULATION OF 56.26 SITE DESIGNATION, IMPROVEMENT, AND USE.] To assure the paramount 56.27 and controlling effect ofthe provisions hereinthis section 56.28 over other state agencies,; regional, county, and local 56.29 governments,; and special purpose government districts, the 56.30 issuance of acertificate ofsitecompatibilitypermit or 56.31transmission line constructionroute permit and subsequent 56.32 purchase and use ofsuchsite or route locations for large 56.33 electric power generating plant and high voltage transmission 56.34 line purposesshall beis the sole site approval required to be 56.35 obtained by the utility.Such certificate orThe permitshall56.36supersedesupersedes andpreempt allpreempts any zoning, 57.1 building, or land use rules, regulations, or ordinances 57.2 promulgated by any regional, county, local, and special purpose 57.3 government. 57.4 Sec. 2. Minnesota Statutes 2000, section 116C.62, is 57.5 amended to read: 57.6 116C.62 [IMPROVEMENT OF SITES AND ROUTES.] 57.7 Utilitieswhichthat have acquired a site or route in 57.8 accordance with sections 116C.51 to 116C.69 may proceed to 57.9 construct or improve the site or route for the intended purposes 57.10 at any time, subject to section 116C.61, subdivision 2,; 57.11 provided that, if the construction and improvementcommences57.12more thanhas not commenced within four years after a 57.13certificate orpermit for the site or route has been issued, 57.14 then the utility must certify to the board that the site or 57.15 route continues to meet the conditions upon which the 57.16 certificate of site compatibility or transmission line 57.17 construction permit was issued. 57.18 Sec. 3. Minnesota Statutes 2000, section 116C.64, is 57.19 amended to read: 57.20 116C.64 [FAILURE TO ACT.] 57.21 If the board fails to act within the times specified in 57.22 section 116C.57, the applicant or any affectedutilityperson 57.23 may seek an order of the district court requiring the board to 57.24 designate or refuse to designate a site or route. 57.25 Sec. 4. Minnesota Statutes 2000, section 116C.645, is 57.26 amended to read: 57.27 116C.645 [REVOCATION OR SUSPENSION.] 57.28 A sitecertificatepermit orconstructionroute permit may 57.29 be revoked or suspended by the board after adequate notice of 57.30 the alleged grounds for revocation or suspension and a full and 57.31 fair hearing in which the affected utility has an opportunity to 57.32 confront any witness and respond to any evidence against it and 57.33 to present rebuttal or mitigating evidence upon a finding by the 57.34 board of: 57.35 (1) any false statement knowingly made in the application 57.36 or in accompanying statements or studies required of the 58.1 applicant, if a true statement would have warranted a change in 58.2 the board's findings; 58.3 (2) failure to comply with material conditions of the site 58.4 certificate or construction permit, or failure to maintain 58.5 health and safety standards; or 58.6 (3) any material violation of the provisions of sections 58.7 116C.51 to 116C.69, any rulepromulgated pursuant thereto58.8 adopted under these sections, or any order of the board. 58.9 Sec. 5. Minnesota Statutes 2000, section 116C.65, is 58.10 amended to read: 58.11 116C.65 [JUDICIAL REVIEW.] 58.12 Anyutilityapplicant, party, or person aggrieved by the 58.13 issuance of acertificatesite or route permit or emergency 58.14certificate of site compatibility or transmission line58.15constructionpermit from the board or a certification of 58.16 continuing suitability filed by a utility with the board or by a 58.17 final order in accordance with any rulespromulgatedadopted by 58.18 the board, may appeal to the court of appeals in accordance with 58.19 chapter 14. The appealshallmust be filed within 60 days after 58.20 the publication in the State Register of notice of the issuance 58.21 of the certificate or permit by the board or certification filed 58.22 with the board or the filing of any final order by the board. 58.23 Sec. 6. Minnesota Statutes 2000, section 116C.66, is 58.24 amended to read: 58.25 116C.66 [RULES.] 58.26 (a) The board, in order to give effect to the purposes of 58.27 sections 116C.51 to 116C.69,shall prior to July 1, 1978,may 58.28 adopt rules consistent with sections 116C.51 to 116C.69, 58.29 includingpromulgationadoption of site and route designation 58.30 criteria,; the description of the information to be furnished by 58.31 the utilities,; establishment of minimum guidelines for public 58.32 participation in the development, revision, and enforcement of 58.33 any rule, plan, or program established by the board,; procedures 58.34 for the revocation or suspension of a construction permit or a 58.35 certificate of site compatibility,; the procedure and timeliness 58.36 for proposing alternative routes and sites,; and route exemption 59.1 criteria and procedures. 59.2No(b) A rule adopted by the boardshallmay not grant 59.3 priority to state-owned wildlife management areas over 59.4 agricultural lands in the designation of route-avoidance areas. 59.5 (c) The provisions of chapter 14shallapply to the appeal 59.6 of rules adopted by the board to the same extent as it applies 59.7 to the review of rules adopted by any other agency of state 59.8 government. 59.9 (d) The chief administrative law judge shall, prior to59.10January 1, 1978,adopt procedural rules for public hearings 59.11 relating to the site and route designation process and to the 59.12 route exemption process. The rulesshallmust attempt to 59.13 maximize citizen participation in these processes. 59.14 Sec. 7. Minnesota Statutes 2000, section 116C.69, is 59.15 amended to read: 59.16 116C.69 [BIENNIAL REPORT;APPLICATION FEES; APPROPRIATION; 59.17 FUNDING.] 59.18 Subdivision 1. [BIENNIAL REPORT.] Before November 15 of 59.19 each even-numbered year the board shall prepare and submit to 59.20 the legislature a report of its operations, activities, 59.21 findings, and recommendations concerning sections 116C.51 to 59.22 116C.69. The report shall also contain information on the 59.23 board's biennial expenditures, its proposed budget for the 59.24 following biennium, and the amounts paid incertificate and59.25 permit application feespursuant to subdivisions 2 and 2aand in 59.26 assessments pursuant tosubdivision 3section 116C.69. The 59.27 proposed budget for the following bienniumshall beis subject 59.28 to legislative review. 59.29 Subd. 2. [SITE APPLICATION FEE.] Every applicant for a 59.30 sitecertificatepermit shall pay to the board a fee in an 59.31 amount equal to $500 for each $1,000,000 of production plant 59.32 investment in the proposed installation as defined in the 59.33 Federal Power Commission Uniform System of Accounts. The board 59.34 shall specify the time and manner of payment of the fee. If any 59.35 single payment requested by the board is in excess of 25 percent 59.36 of the total estimated fee, the board shall show that the excess 60.1 is reasonably necessary. The applicant shall pay within 30 days 60.2 of notification any additional fees reasonably necessary for 60.3 completion of the site evaluation and designation process by the 60.4 board.In no event shallThe total fees required of the 60.5 applicant under this subdivision must never exceed an amount 60.6 equal to 0.001 ofsaidthe production plant investment(, which 60.7 equals $1,000 for each $1,000,000). All money receivedpursuant60.8tounder this subdivisionshallmust be deposited in a special 60.9 account. Money in the account is appropriated to the board to 60.10 pay expenses incurred in processing applications 60.11 forcertificatessite permits in accordance with sections 60.12 116C.51 to 116C.69 andin the event, if the expenses are less 60.13 than the fee paid, to refund the excess to the applicant. 60.14 Subd. 2a. [ROUTE APPLICATION FEE.] Every applicant for a 60.15 transmission lineconstructionroute permit shall pay to the 60.16 board a base fee of $35,000 plus a fee in an amount equal to 60.17 $1,000 per mile length of the longest proposed route. The board 60.18 shall specify the time and manner of payment of the fee. If any 60.19 single payment requested by the board is in excess of 25 percent 60.20 of the total estimated fee, the board shall show that the excess 60.21 is reasonably necessary.In the eventIf the actual cost of 60.22 processing an application up to the board's final decision to 60.23 designate a route exceedsthe abovethis fee schedule, the board 60.24 may assess the applicant any additional fees necessary to cover 60.25 the actual costs, not to exceed an amount equal to $500 per mile 60.26 length of the longest proposed route. All money received 60.27pursuant tounder this subdivisionshallmust be deposited in a 60.28 special account. Money in the account is appropriated to the 60.29 board to pay expenses incurred in processing applications for 60.30constructionroute permits in accordance with sections 116C.51 60.31 to 116C.69 andin the event, if the expenses are less than the 60.32 fee paid, to refund the excess to the applicant. 60.33 Subd. 3. [FUNDING; ASSESSMENT.] (a) The board shall 60.34 finance its base line studies, general environmental studies, 60.35 development of criteria, inventory preparation, monitoring of 60.36 conditions placed on sitecertificatesandconstructionroute 61.1 permits, and all other work, other than specific site and route 61.2 designation, from an assessment made quarterly, at least 30 days 61.3 before the start of each quarter, by the board against all 61.4 utilities with annual retail kilowatt-hour sales greater than 61.5 4,000,000 kilowatt-hours in the previous calendar year. 61.6 (b) Each shareshallmust be determined as follows: 61.7 (1) the ratio that the annual retail kilowatt-hour sales in 61.8 the state of each utility bears to the annual total retail 61.9 kilowatt-hour sales in the state of all these utilities, 61.10 multiplied by 0.667,; plus 61.11 (2) the ratio that the annual gross revenue from retail 61.12 kilowatt-hour sales in the state of each utility bears to the 61.13 annual total gross revenues from retail kilowatt-hour sales in 61.14 the state of all these utilities, multiplied by 0.333, as 61.15 determined by the board. 61.16 (c) The assessmentshallmust be credited to the special 61.17 revenue fund andshall bepaid to the state treasury within 30 61.18 days after receipt of the bill, which shall constitute notice of 61.19saidthe assessment and its demand of paymentthereof. 61.20 (d) The total amountwhichthat may be assessed to the 61.21 several utilities under the authority of this subdivisionshall61.22 may not exceed the sum of the annual budget of the board for 61.23 carrying out the purposes of this subdivision. 61.24 (e) The assessment for the second quarter of each fiscal 61.25 yearshallmust be adjusted to compensate for the amount by 61.26 which actual expenditures by the board for the preceding fiscal 61.27 year were more or less than the estimated expenditures 61.28 previously assessed. 61.29 Sec. 8. Minnesota Statutes 2000, section 216B.03, is 61.30 amended to read: 61.31 216B.03 [REASONABLE RATE.] 61.32 (a) Every rate made, demanded, or received by any public 61.33 utility, or by any two or more public utilities jointly,shall61.34 must be just and reasonable. Ratesshallmust not be 61.35 unreasonably preferential,or unreasonably prejudicial or 61.36 discriminatory, butshallmust be sufficient, equitable, and 62.1 consistent in application to a class of consumers. To the 62.2 maximum reasonable extent, the commission shall set rates to 62.3 encourage energy conservation and renewable energy use and to 62.4 further the goals of sections 216B.164, 216B.241, 216B.2411, and 62.5 216C.05. Any doubt as to reasonableness should be resolved in 62.6 favor of the consumer. 62.7 (b) For rate-making purposes a public utility may treat two 62.8 or more municipalities served by it as a single class wherever 62.9 the populations are comparable in size or the conditions of 62.10 service are similar. 62.11 Sec. 9. Minnesota Statutes 2000, section 216B.16, 62.12 subdivision 1, is amended to read: 62.13 Subdivision 1. [NOTICE.] Unless the commission otherwise 62.14 orders, no public utility shall change a ratewhichthat has 62.15 been duly established under this chapter, except upon 60 days' 62.16 notice to the commission. The noticeshallmust include 62.17 statements of facts, expert opinions, substantiating documents, 62.18 and exhibits, supporting the change requested, and state the 62.19 change proposed to be made in the rates then in force and the 62.20 time when the modified rates will go into effect.If the filing62.21utility does not have an approved conservation improvement plan62.22on file with the department of public service, it shall also62.23include in its notice an energy conservation plan pursuant to62.24section 216B.241.The filing utility shall give written notice, 62.25 as approved by the commission, of the proposed change to the 62.26 governing body of each municipality and county in the area 62.27 affected. All proposed changesshallmust be shown by filing 62.28 new schedules orshallbe plainly indicated upon schedules on 62.29 file and in force at the time. 62.30 Sec. 10. Minnesota Statutes 2000, section 216B.16, 62.31 subdivision 6b, is amended to read: 62.32 Subd. 6b. [ENERGY CONSERVATION IMPROVEMENT.] (a) Except as 62.33 otherwise provided in this subdivision, all investments and 62.34 expenses of a public utility as defined in section 216B.241, 62.35 subdivision 1, paragraph (e), incurred in connection with energy 62.36 conservation improvementsshallunder either section 216B.241 or 63.1 216B.2411 must be recognized and included by the commission in 63.2 the determination of just and reasonable rates as if the 63.3 investments and expenses were directly made or incurred by the 63.4 utility in furnishing utility service. 63.5 (b) After December 31, 1999, investments and expenses for 63.6 energy conservation improvementsshallmust not be included by 63.7 the commission in the determination of just and reasonable 63.8 electric and gas rates for retail electric and gas service 63.9 provided to large electric customer facilities that have been 63.10 exempted by the commissionerof the department of public service63.11 pursuant to section 216B.241, subdivision 1a, paragraph (b). 63.12 However,noa public utilityshallmay not be prevented from 63.13 recovering its investment in energy conservation improvements 63.14 from all customers that were made on or before December 31, 63.15 1999, in compliance with the requirements of section 216B.241. 63.16 (c) The commission may permit a public utility to file rate 63.17 schedules providing for annual recovery of the costs of energy 63.18 conservation improvements under either section 216B.241 or 63.19 216B.2411. These rate schedules may be applicable to less than 63.20 all the customers in a class of retail customers if necessary to 63.21 reflect the differing minimum spending requirements of section 63.22 216B.241, subdivision 1a. After December 31, 1999, the 63.23 commission shall allow a public utility, without requiring a 63.24 general rate filing under this section, to reduce the electric 63.25 and gas rates applicable to large electric customer facilities 63.26 that have been exempted by the commissionerof the department of63.27public servicepursuant to section 216B.241, subdivision 1a, 63.28 paragraph (b), by an amount that reflects the elimination of 63.29 energy conservation improvement investments or expenditures for 63.30 those facilities required on or before December 31, 1999.In63.31the event thatIf the commission has set electric or gas rates 63.32 based on the use of an accounting methodology that results in 63.33 the cost of conservation improvements being recovered from 63.34 utility customers over a period of years, the rate reduction may 63.35 occur in a series of steps to coincide with the recovery of 63.36 balances due to the utility for conservation improvements made 64.1 by the utility on or before December 31, 1999. 64.2 Sec. 11. Minnesota Statutes 2000, section 216B.16, 64.3 subdivision 6c, is amended to read: 64.4 Subd. 6c. [INCENTIVE PLAN FOR ENERGY CONSERVATION 64.5 IMPROVEMENT.] (a) The commission may order public utilities to 64.6 develop and submit for commission approval incentive plans that 64.7 describe the method of recovery and accounting for utility 64.8 conservation expenditures and savings under either section 64.9 216B.241 or 216B.2411. In developing the incentive plans the 64.10 commission shall ensure the effective involvement of interested 64.11 parties. 64.12 (b) In approving incentive plans, the commission shall 64.13 consider: 64.14 (1) whether the plan is likely to increase utility 64.15 investment in cost-effective energy conservation; 64.16 (2) whether the plan is compatible with the interest of 64.17 utility ratepayers and other interested parties; 64.18 (3) whether the plan links the incentive to the utility's 64.19 performance in achieving cost-effective conservation; and 64.20 (4) whether the plan is in conflict with other provisions 64.21 of this chapter. 64.22 (c) The commission may set rates to encourage the vigorous 64.23 and effective implementation of utility conservation programs. 64.24 The commission may: 64.25 (1) increase or decrease any otherwise allowed rate of 64.26 return on net investment based upon the utility's skill, 64.27 efforts, and success in conserving energy; 64.28 (2) share between ratepayers and utilities the net savings 64.29 resulting from energy conservation programs to the extent 64.30 justified by the utility's skill, efforts, and success in 64.31 conserving energy; and 64.32 (3) compensate the utility for earnings lost as a result of 64.33 its conservation programs. 64.34 Sec. 12. Minnesota Statutes 2000, section 216B.162, 64.35 subdivision 8, is amended to read: 64.36 Subd. 8. [ENERGY EFFICIENCY IMPROVEMENT; EXPENSE 65.1 RECOVERY.] If the commission approves a competitive rate or the 65.2 parties agree to a modified rate, the commission may require the 65.3 electric utility to provide the customer with an energy audit 65.4 and assist in implementing cost-effective energy efficiency 65.5 improvements to assure that the customer's use of electricity is 65.6 efficient. An investment in cost-effective energy conservation 65.7 improvements required under this section must be treated as an 65.8 energy conservation improvement program and included in 65.9 thedepartment'sdetermination of significant investments under 65.10 section 216B.241 or 216B.2411. The utility shall recover energy 65.11 conservation improvement expenses in a rate proceeding under 65.12 section 216B.16 or 216B.17 in the same manner as the commission 65.13 authorizes for the recovery of conservation expenditures made 65.14 under section 216B.241 or 216B.2411. 65.15 Sec. 13. Minnesota Statutes 2000, section 216B.1621, 65.16 subdivision 2, is amended to read: 65.17 Subd. 2. [COMMISSION APPROVAL.] (a) The commission shall 65.18 approve an agreement under this section upon finding that: 65.19 (1) the proposed electric service power generation facility 65.20 could reasonably be expected to qualify for a market value 65.21 exclusion under section 272.0211; 65.22 (2) the public utility has a contractual option to purchase 65.23 electric power from the proposed facility; and 65.24 (3) the public utility can use the output from the proposed 65.25 facility to meet its future need for power as demonstrated in 65.26 the most recent resource plan filed with and approved by the 65.27 commissionunder section 216B.2422. 65.28 (b) Sections 216B.03, 216B.05, 216B.06, 216B.07, 216B.16, 65.29 216B.162, and 216B.23 do not apply to an agreement under this 65.30 section. 65.31 Sec. 14. Minnesota Statutes 2000, section 216B.164, 65.32 subdivision 4, is amended to read: 65.33 Subd. 4. [PURCHASES; WHEELING; COSTS.] (a) Except as 65.34 otherwise provided in paragraph (c), this subdivision shall 65.35 apply to all qualifying facilities having 40-kilowatt capacity 65.36 or more as well as qualifying facilities as defined in 66.1 subdivision 3 which elect to be governed by its provisions. 66.2 (b) The utility to which the qualifying facility is 66.3 interconnected shall purchase all energy and capacity made 66.4 available by the qualifying facility. The qualifying facility 66.5 shall be paid the utility's full avoided capacity and energy 66.6 costs as negotiated by the parties, as set by the commission, or 66.7 as determined through competitive bidding approved by the 66.8 commission. The full avoided capacity and energy costs to be 66.9 paid a qualifying facility that generates electric power by 66.10 means of a renewable energy source are the utility's least cost 66.11 renewable energy facility or the bid of a competing supplier of 66.12 a least cost renewable energy facility, whichever is lower, 66.13 unless thecommission's resource plan order, under section66.14216B.2422, subdivision 2, providescommission determines that 66.15 the use of a renewable resource to meet the identified capacity 66.16 need is not in the public interest. 66.17 (c) For all qualifying facilities having 30-kilowatt 66.18 capacity or more, the utility shall, at the qualifying 66.19 facility's or the utility's request, provide wheeling or 66.20 exchange agreements wherever practicable to sell the qualifying 66.21 facility's output to any other Minnesota utility having 66.22 generation expansion anticipated or planned for the ensuing ten 66.23 years. The commission shall establish the methods and 66.24 procedures to insure that except for reasonable wheeling charges 66.25 and line losses, the qualifying facility receives the full 66.26 avoided energy and capacity costs of the utility ultimately 66.27 receiving the output. 66.28 (d) The commission shall set rates for electricity 66.29 generated by renewable energy. 66.30 Sec. 15. Minnesota Statutes 2000, section 216B.2423, 66.31 subdivision 2, is amended to read: 66.32 Subd. 2. [RESOURCE PLANNING MANDATE.] The public utilities 66.33 commission shall order a public utility subject to subdivision 66.34 1, to construct and operate, purchase, or contract to purchase 66.35 an additional 400 megawatts of electric energy installed 66.36 capacity generated by wind energy conversion systems by December 67.1 31, 2002, subject to any resource planning and least cost 67.2 planning requirementsin section 216B.2422. 67.3 Sec. 16. Minnesota Statutes 2000, section 216C.17, 67.4 subdivision 3, is amended to read: 67.5 Subd. 3. [DUPLICATION.] The commissioner shall, to the 67.6 maximum extent feasible, provide that forecasts required under 67.7 this section be consistent with material required by other state 67.8 and federal agencies in order to prevent unnecessary 67.9 duplication. Electric utilities submitting advance forecasts as 67.10 part of an integrated resource plan filed pursuant tosection67.11216B.2422 andpublic utilities commission rules are excluded 67.12 from the annual reporting requirement in subdivision 2. 67.13 Sec. 17. [INSTRUCTION TO REVISOR.] 67.14 The revisor of statutes shall renumber Minnesota Statutes, 67.15 section 116C.69, subdivision 1, as Minnesota Statutes, section 67.16 116C.681. 67.17 ARTICLE 6 67.18 MISCELLANEOUS PROVISIONS 67.19 Section 1. Minnesota Statutes 2000, section 216A.03, 67.20 subdivision 3a, is amended to read: 67.21 Subd. 3a. [POWERS AND DUTIES OF CHAIR.] The chairshall be67.22 is the principal executive officer of the commission and shall 67.23 preside at meetings of the commission. The responsibilities of 67.24 the chairshall organizeinclude: 67.25 (1) organizing the work of the commissionand may make; 67.26 (2) making assignments to commission members,appoint67.27committees and giveas appropriate; 67.28 (3) appointing subcommittees; 67.29 (4) giving direction to the commission staff through the 67.30 executive secretary subject to the approval of the commission.; 67.31 (5) supervising the work of the executive secretary; and 67.32 (6) in coordination with the executive secretary, 67.33 participating in employment and termination decisions, including 67.34 representing the commission in grievance proceedings; addressing 67.35 employee complaints and grievances; developing and implementing 67.36 the agency budget; testifying before legislative committees and 68.1 working with legislators as requested; determining agency-wide 68.2 training needs and initiatives; implementing computer technology 68.3 updates; administering and implementing relations with the 68.4 department of commerce, the office of the attorney general, and 68.5 other agencies; and developing and implementing strategies for 68.6 the commission to adapt to rapid changes in the industries the 68.7 commission oversees. 68.8 Sec. 2. Minnesota Statutes 2000, section 216B.095, is 68.9 amended to read: 68.10 216B.095 [DISCONNECTION DURING COLD WEATHER.] 68.11 The commission shall amend its rules governing 68.12 disconnection of residential utility customers who are unable to 68.13 pay for utility service during cold weather to include the 68.14 following: 68.15 (1) coverage of customers whose household income is less 68.16 than185 percent of the federal poverty level50 percent of the 68.17 state median income; 68.18 (2) a requirement that a customer who pays the utility at 68.19 least ten percent of the customer's income or the full amount of 68.20 the utility bill, whichever is less, in a cold weather month 68.21 cannot be disconnected during that month; 68.22 (3) that the ten percent figure in clause (2) must be 68.23 prorated between energy providers proportionate to each 68.24 provider's share of the customer's total energy costs where the 68.25 customer receives service from more than one provider; 68.26(4) that a customer's household income does not include any68.27amount received for energy assistance;68.28(5)(4) verification of income by the local energy 68.29 assistance provider or the utility, unless the customer is 68.30 automatically eligible for protection against disconnection as a 68.31 recipient of any form of public assistance, including energy 68.32 assistance, that uses income eligibility in an amount at or 68.33 below the income eligibility in clause (1);and68.34(6)(5) a requirement that the customer receive, from the68.35local energy assistance provider or other entity, budget68.36counseling and referralreferrals to energy assistance programs, 69.1 weatherization, conservation, or other programs likely to reduce 69.2 the customer'sconsumption ofenergy bills; 69.3 (6) a requirement that customers who have demonstrated an 69.4 inability to pay on forms for such purposes provided by the 69.5 utility, and who make reasonably timely payments to the utility 69.6 under a payment plan that considers the financial resources of 69.7 the household, cannot be disconnected from utility services from 69.8 October 15 to April 15. A customer who is receiving energy 69.9 assistance is deemed to have demonstrated an inability to pay. 69.10 For the purpose of clause (2), the "customer's income" means the 69.11 actual monthly income of the customer exceptfor a customer who69.12is normally employed only on a seasonal basis and whose annual69.13income is over 135 percent of the federal poverty level, in69.14which case the customer's income isor the average monthly 69.15 income of the customer computed on an annual calendar year 69.16basis, whichever is less, and does not include any amount 69.17 received for energy assistance. 69.18 Sec. 3. Minnesota Statutes 2000, section 216B.097, 69.19 subdivision 1, is amended to read: 69.20 Subdivision 1. [APPLICATION; NOTICE TO RESIDENTIAL 69.21 CUSTOMER.] (a) A municipal utility or a cooperative electric 69.22 association must not disconnect the utility service of a 69.23 residential customer during the period between October 15 and 69.24 April 15 if the disconnection affects the primary heat source 69.25 for the residential unit when the following conditions are met: 69.26(1) the disconnection would occur during the period between69.27October 15 and April 15;69.28(2)(1) the customer has declared inability to pay on forms 69.29 provided by the utility. For the purpose of this clause, a 69.30 customer that is receiving energy assistance is deemed to have 69.31 demonstrated an inability to pay; 69.32(3)(2) the household income of the customer is less than 69.33185 percent of the federal poverty level, as documented by the69.34customer to the utility; and50 percent of the state median 69.35 income; 69.36 (3) verification of income may be conducted by the local 70.1 energy assistance provider or the utility, unless the customer 70.2 is automatically eligible for protection against disconnection 70.3 as a recipient of any form of public assistance, including 70.4 energy assistance, that uses income eligibility in an amount at 70.5 or below the income eligibility in clause (2); 70.6 (4)the customer'sa customer whose account is current for 70.7 the billing period immediately prior to October 15 orthe70.8customer has enteredenters into a payment schedule that 70.9 considers the financial resources of the household and is 70.10 reasonably current with payments under the schedule; and 70.11 (5) the customer receives referrals to energy assistance 70.12 programs, and weatherization, conservation, or other programs to 70.13 reduce the customer's energy bills. 70.14 (b) A municipal utility or a cooperative electric 70.15 association must, between August 15 and October 15 of each year, 70.16 notify all residential customers of the provisions of this 70.17 section. 70.18 Sec. 4. [216B.098] [CUSTOMER PROTECTIONS.] 70.19 Subdivision 1. [APPLICABILITY.] This section applies to 70.20 residential customers of public utilities, municipal utilities, 70.21 and cooperative electric associations. 70.22 Subd. 2. [BUDGET BILLING PLANS.] A utility shall offer a 70.23 customer a budget billing plan for payment of charges for 70.24 service, including adequate notice to customers prior to 70.25 changing budget payment amounts. Municipal utilities having 70.26 3,000 or fewer customers are exempt from this requirement. 70.27 Municipal utilities having more than 3,000 customers shall 70.28 implement this requirement within two years of the effective 70.29 date of this chapter. 70.30 Subd. 3. [PAYMENT AGREEMENTS.] A utility shall offer a 70.31 payment agreement for the payment of arrears. 70.32 Subd. 4. [UNDERCHARGES.] A utility shall offer a payment 70.33 agreement to customers who have been undercharged if no culpable 70.34 conduct by the customer or resident of the customer's household 70.35 caused the undercharge. The agreement must cover a period equal 70.36 to the time over which the undercharge occurred or a different 71.1 time period that is mutually agreeable to the customer and the 71.2 utility. No interest or delinquency fee may be charged under 71.3 this agreement. 71.4 Subd. 5. [MEDICALLY NECESSARY EQUIPMENT.] A utility shall 71.5 reconnect or continue service to a customer's residence where a 71.6 medical emergency exists or where medical equipment requiring 71.7 electricity is necessary to sustain life is in use, provided 71.8 that the utility receives from a medical doctor written 71.9 certification, or initial certification by telephone and written 71.10 certification within five business days, that failure to 71.11 reconnect or continue service will impair or threaten the health 71.12 or safety of a resident of the customer's household. The 71.13 customer must enter into a payment agreement. 71.14 Subd. 6. [COMMISSION AUTHORITY.] The commission, or staff 71.15 designated by the commission, has the authority to order 71.16 resolutions of disputes involving alleged violations of this 71.17 chapter or any other disputes involving public utilities coming 71.18 within its jurisdiction. 71.19 Sec. 5. [216B.79] [PREVENTATIVE MAINTENANCE.] 71.20 (a) The commission has the authority to ensure that public 71.21 utilities are making adequate infrastructure investments and 71.22 undertaking sufficient preventative maintenance with regard to 71.23 such facilities. 71.24 (b) The commission may make appropriate adjustments in a 71.25 utility's rates, or make a recommendation to the Federal Energy 71.26 Regulatory Commission to make an appropriate adjustment in a 71.27 utility's allowed rate of return on those utilities' 71.28 transmission facilities, to offset the costs of such 71.29 construction. 71.30 Sec. 6. Minnesota Statutes 2000, section 216C.41, is 71.31 amended to read: 71.32 216C.41 [RENEWABLE ENERGY PRODUCTION INCENTIVE.] 71.33 Subdivision 1. [DEFINITIONS.] (a) The definitions in this 71.34 subdivision apply to this section. 71.35 (b) "Qualified hydroelectric facility" means a 71.36 hydroelectric generating facility in this state that: 72.1 (1) is located at the site of a dam, if the dam was in 72.2 existence as of March 31, 1994; and 72.3 (2) either (i) begins generating electricity after July 1, 72.4 1994; or (ii) is generating electricity as of June 30, 2001, and 72.5 undergoes substantial refurbishing after that date, to be 72.6 completed by December 31, 2005. 72.7 (c) "Qualified wind energy conversion facility" means a 72.8 wind energy conversion system that: 72.9 (1) produces two megawatts or less of electricity as 72.10 measured by nameplate rating and begins generating electricity 72.11 after June 30, 1997, and before July 1, 1999; 72.12 (2) begins generating electricity after June 30, 1999, 72.13 produces two megawatts or less of electricity as measured by 72.14 nameplate rating, and is: 72.15 (i) located within one county and owned by a natural person 72.16 who owns the land where the facility is sited; 72.17 (ii) owned by a Minnesota small business as defined in 72.18 section 645.445; 72.19 (iii) owned by a nonprofit organization; or 72.20 (iv) owned by a tribal council if the facility is located 72.21 within the boundaries of the reservation; or 72.22 (3) begins generating electricity after June 30, 1999, 72.23 produces seven megawatts or less of electricity as measured by 72.24 nameplate rating, and: 72.25 (i) is owned by a cooperative organized under chapter 308A; 72.26 and 72.27 (ii) all shares and membership in the cooperative are held 72.28 by natural persons or estates, at least 51 percent of whom 72.29 reside in a county or contiguous to a county where the wind 72.30 energy production facilities of the cooperative are located. 72.31 Subd. 2. [INCENTIVE PAYMENT.] (a) Incentive payments shall 72.32 be made according to this section to the owner or operator of a 72.33 qualified hydropower facility or qualified wind energy 72.34 conversion facility for electric energy generated and sold by 72.35 the facility or, except as provided in paragraph (b) for a 72.36 publicly owned hydropower facility, for electric energy that is 73.1 generated by the facility and used by the owner of the facility 73.2 outside the facility. 73.3 (b) For a facility that is publicly owned and in need of 73.4 substantial refurbishment and repair, the incentive payment 73.5 shall be made to the public owner of the facility to finance 73.6 structural repairs and replacement of structural components. 73.7 (c) Payment may only be made upon receipt by the 73.8 commissioner of finance of an incentive payment application that 73.9 establishes that the applicant is eligible to receive an 73.10 incentive payment and that satisfies other requirements the 73.11 commissioner deems necessary. The application shall be in a 73.12 form and submitted at a time the commissioner establishes. 73.13 There is annually appropriated from the general fund sums 73.14 sufficient to make the payments required under this section. 73.15 Subd. 3. [ELIGIBILITY WINDOW.] Payments may be made under 73.16 this section only for electricity generated: 73.17 (1) from a qualified hydroelectric facility that is 73.18 operational and generating electricity before December 31, 2001, 73.19 or that undergoes substantial refurbishing after June 30, 2001, 73.20 to be completed by December 31, 2005; or 73.21 (2) from a qualified wind energy conversion facility that 73.22 is operational and generating electricity before January 1, 2005. 73.23 Subd. 4. [PAYMENT PERIOD.] A facility may receive payments 73.24 under this section for a ten-year period. No payment under this 73.25 section may be made for electricity generated: 73.26 (1) by a qualified hydroelectric facility after December 73.27 31, 2010, or December 31, 2015, if the facility undergoes 73.28 substantial refurbishing after June 30, 2001; or 73.29 (2) by a qualified wind energy conversion facility after 73.30 December 31, 2015. 73.31 The payment period begins and runs consecutively from the 73.32 first year in which electricity generated from the facility is 73.33 eligible for incentive payment. 73.34 Subd. 5. [AMOUNT OF PAYMENT.] (a) An incentive payment is 73.35 based on the number of kilowatt hours of electricity generated. 73.36 The amount of the payment is 1.5 cents per kilowatt hour. For 74.1 electricity generated by qualified wind energy conversion 74.2 facilities, the incentive payment under this section is limited 74.3 to no more than 100 megawatts of nameplate capacity. During any 74.4 period in which qualifying claims for incentive payments exceed 74.5 100 megawatts of nameplate capacity, the payments must be made 74.6 to producers in the order in which the production capacity was 74.7 brought into production. 74.8 (b) Beginning July 1, 2001, a qualified wind energy 74.9 conversion facility defined under subdivision 1, paragraph (c), 74.10 clause (1), (2), or (3), may not be located within five miles of 74.11 another qualified wind energy conversion facility constructed 74.12 within the same calendar year and owned by the same person. For 74.13 the purposes of this paragraph, the department shall determine 74.14 that the same person owns two qualified wind energy conversion 74.15 facilities when the underlying ownership structure contains 74.16 similar persons or entities, other than a person or entity that 74.17 provides equity financing, even if the ownership shares differ 74.18 between the facilities. 74.19 Subd. 6. [OWNERSHIP; FINANCING; CURE.] (a) For the 74.20 purposes of subdivision 1, paragraph (c), clause (2), a wind 74.21 energy conversion facility qualifies if it is owned at least 51 74.22 percent by one or more of any combination of the entities listed 74.23 in that clause. 74.24 (b) A subsequent owner of a qualified facility may continue 74.25 to receive the incentive payment for the duration of the 74.26 original payment period if the subsequent owner qualifies for 74.27 the incentive under subdivision 1. 74.28 (c) Nothing in this section may be construed to deny 74.29 incentive payment to an otherwise qualified facility that has 74.30 obtained debt or equity financing for construction or operation 74.31 as long as the ownership requirements of subdivision 1 and this 74.32 subdivision are met. If, during the incentive payment period 74.33 for a qualified facility, the owner of the facility is in 74.34 default of a lending agreement and the lender takes possession 74.35 of and operates the facility and makes reasonable efforts to 74.36 transfer ownership of the facility to an entity other than the 75.1 lender, the lender may continue to receive the incentive payment 75.2 for electricity generated and sold by the facility for a period 75.3 not to exceed 18 months. A lender who takes possession of a 75.4 facility shall notify the commissioner immediately on taking 75.5 possession and, at least quarterly, document efforts to transfer 75.6 ownership of the facility. 75.7 (d) If, during the incentive payment period, a qualified 75.8 facility loses the right to receive the incentive because of 75.9 changes in ownership, the facility may regain the right to 75.10 receive the incentive upon cure of the ownership structure that 75.11 resulted in the loss of eligibility and may reapply for the 75.12 incentive, but in no case may the payment period be extended 75.13 beyond the original ten-year limit. 75.14 (e) A subsequent or requalifying owner under paragraph (b) 75.15 or (d) retains the facility's original priority order for 75.16 incentive payments as long as the ownership structure 75.17 requalifies within two years from the date the facility became 75.18 unqualified or two years from the date a lender takes possession 75.19 of the facility. 75.20 Sec. 7. [REPEALER.] 75.21 (a) Minnesota Statutes 2000, sections 216B.241, subdivision 75.22 1c, and 216C.18, are repealed. 75.23 (b) Minnesota Statutes 2000, section 216B.2422, 75.24 subdivisions 2 and 6, are repealed September 1, 2002. 75.25 Sec. 8. [EFFECTIVE DATE.] 75.26 Articles 3 to 6 are effective the day following final 75.27 enactment, except that those provisions referring or relating to 75.28 article 1, section 2 or 3, the independent reliability 75.29 administrator or the state reliability plan, are effective July 75.30 1, 2002. 75.31 ARTICLE 7 75.32 SAFETY AND SERVICE STANDARDS 75.33 Section 1. [216B.81] [DEFINITIONS.] 75.34 Subdivision 1. [SCOPE.] The terms used in this article 75.35 have the meanings given them in this section. 75.36 Subd. 2. [AVERAGE NUMBER OF CUSTOMERS SERVED.] "Average 76.1 number of customers served" means the number of active, metered, 76.2 customer accounts available in a utility's 76.3 interruption-reporting database on the day that an interruption 76.4 occurs. 76.5 Subd. 3. [CIRCUIT.] "Circuit" means a set of conductors 76.6 serving customer loads that are capable of being separated from 76.7 the serving substation automatically by a recloser, fuse, 76.8 sectionalizing equipment, and other devices. 76.9 Subd. 4. [COMPONENT.] "Component" means a piece of 76.10 equipment, a line, a section of line, or a group of items that 76.11 is an entity for purposes of reporting, analyzing, and 76.12 predicting interruptions. 76.13 Subd. 5. [CUSTOMER.] "Customer" means a contiguous 76.14 electrical service location, regardless of the number of meters 76.15 at the location. 76.16 Subd. 6. [CUSTOMER INTERRUPTION.] "Customer interruption" 76.17 means the loss of service due to a forced outage for more than 76.18 five minutes, for one or more customers, which is the result of 76.19 one or more component failures. 76.20 Subd. 7. [CUSTOMERS' INTERRUPTIONS CAUSED BY POWER 76.21 RESTORATION PROCESS.] "Customers' interruptions caused by power 76.22 restoration process" means when customers lose power as a result 76.23 of the process of restoring power. The duration of these 76.24 outages is included in the customer-minutes of interruption. 76.25 Only the customers affected by the power restoration outages 76.26 that were not affected by the original outage are added to the 76.27 number of customer interruptions. 76.28 Subd. 8. [CUSTOMER-MINUTES OF 76.29 INTERRUPTION.] "Customer-minutes of interruption" means the 76.30 number of minutes of forced outage duration multiplied by the 76.31 number of customers affected. 76.32 Subd. 9. [ELECTRIC DISTRIBUTION LINE.] "Electric 76.33 distribution line" means circuits operating at less than 40,000 76.34 volts. 76.35 Subd. 10. [FORCED OUTAGE.] "Forced outage" means an outage 76.36 that cannot be deferred. 77.1 Subd. 11. [MAJOR CATASTROPHIC EVENTS.] "Major catastrophic 77.2 events" means events that are beyond the utility's control that 77.3 result in widespread system damages causing customer 77.4 interruptions that affect at least ten percent of the customers 77.5 in the system or in an operating area or that result in 77.6 customers being without electric service for durations of at 77.7 least 24 hours. 77.8 Subd. 12. [MAJOR STORM.] "Major storm" means a period of 77.9 severe adverse weather resulting in widespread system damage 77.10 causing customer interruptions that affect at least ten percent 77.11 of the customers on the system or in an operating area or that 77.12 result in customers being without electric service for durations 77.13 of at least 24 hours. 77.14 Subd. 13. [MOMENTARY INTERRUPTION.] "Momentary 77.15 interruption" means an interruption of electric service with a 77.16 duration shorter than the time necessary to be classified as a 77.17 customer interruption. 77.18 Subd. 14. [OPERATING AREA.] "Operating area" means a 77.19 geographical subdivision of each electric utility's service 77.20 territory that functions under the direction of a company office 77.21 and may be used for reporting interruptions under this article. 77.22 These areas may also be referred to as regions, divisions, or 77.23 districts. 77.24 Subd. 15. [OUTAGE.] "Outage" means the failure of a power 77.25 system component that results in one or more customer 77.26 interruptions. 77.27 Subd. 16. [OUTAGE DURATION.] "Outage duration" means the 77.28 one minute or greater period from the initiation of an 77.29 interruption to a customer until service has been restored to 77.30 that customer. 77.31 Subd. 17. [PARTIAL CIRCUIT OUTAGE CUSTOMER 77.32 COUNT.] "Partial circuit outage customer count" means when only 77.33 part of a circuit experiences an outage, the number of customers 77.34 affected is estimated, unless an actual count is available. 77.35 When power is partially restored, the number of customers 77.36 restored is also estimated. Most utilities use estimates based 78.1 on the portion of the circuit restored. 78.2 Subd. 18. [PLANNED OUTAGES.] "Planned outages" means those 78.3 outages scheduled by the utility. These interruptions are 78.4 sometimes necessary to connect new customers or perform 78.5 maintenance activities safely. They must not be included in the 78.6 calculation of reliability indexes. 78.7 Subd. 19. [RELIABILITY.] "Reliability" means the degree to 78.8 which electric service is supplied without interruption. 78.9 Subd. 20. [RELIABILITY INDEXES.] "Reliability indexes" 78.10 include the following performance indices for measuring 78.11 frequency and duration of service interruptions: 78.12 (a) The system average interruption frequency index is the 78.13 average number of interruptions per customer per year. It is 78.14 determined by dividing the total annual number of customer 78.15 interruptions by the average number of customers served during 78.16 the year. 78.17 (b) The system average interruption duration index is the 78.18 average customer-minutes of interruption per customer. It is 78.19 determined by dividing the annual sum of customer-minutes of 78.20 interruption by the average number of customers served during 78.21 the year. 78.22 (c) The customer average interruption duration index is the 78.23 average customer-minutes of interruption per customer 78.24 interruption. It approximates the average length of time 78.25 required to complete service restoration. It is determined by 78.26 dividing the annual sum of all customer-minutes of interruption 78.27 durations by the annual number of customer interruptions. 78.28 Sec. 2. [216B.82] [RECORDING SERVICE INTERRUPTION 78.29 INDEXES.] 78.30 Subdivision 1. [SYSTEM INTERRUPTION DATA.] Each electric 78.31 utility with 6,000 retail customers or more shall keep a record 78.32 of the necessary interruption data and calculate the system 78.33 average interruption frequency index, system average 78.34 interruption duration index, and customer average interruption 78.35 duration index of its system, and of each operating area, if 78.36 applicable, at the end of each calendar year for the previous 79.1 12-month period. 79.2 Subd. 2. [CIRCUIT INTERRUPTION DATA.] Unless a utility 79.3 uses alternative criteria as provided in section 216B.83, 79.4 subdivision 2, paragraph (d), each utility also shall, at the 79.5 end of each calendar year, calculate the system average 79.6 interruption frequency index, system average interruption 79.7 duration index, and customer average interruption duration index 79.8 for each circuit in each operating area. Each circuit in each 79.9 operating area must then be listed in order separately according 79.10 to its system average interruption frequency index, its system 79.11 average interruption duration index, and its customer average 79.12 interruption duration index, beginning with the highest values 79.13 for each index. 79.14 Sec. 3. [216B.83] [ANNUAL REPORT.] 79.15 Subdivision 1. [SUMMARY REPORT GENERALLY.] Beginning on 79.16 July 1, 2002, and by July 1 of every year thereafter, each 79.17 electric utility with 6,000 retail customers or more shall file 79.18 with the commission, or in the case of a cooperative electric 79.19 association or municipal utility, with the local governing body 79.20 of the utility or association a report summarizing various 79.21 measures of reliability. The form of the report is subject to 79.22 review and comment by the commission staff. Names and numbers 79.23 used to identify operating areas or individual circuits may 79.24 conform to the utility's practice, but should allow ready 79.25 identification of the geographic location or the general area 79.26 served. Electronic recording and reporting of the required data 79.27 and information is encouraged. 79.28 Subd. 2. [INFORMATION REQUIRED.] (a) The report must 79.29 include at least the information described in paragraphs (b) to 79.30 (h). 79.31 (b) The report must provide an overall assessment of the 79.32 reliability of performance including the aggregate system 79.33 average interruption frequency index, system average 79.34 interruption duration index, and customer average interruption 79.35 duration index by system and each operating area, as applicable. 79.36 (c) The report must include a list of the worst performing 80.1 circuits based on system average interruption frequency index, 80.2 system average interruption duration index, and customer average 80.3 interruption duration index for the calendar year. This portion 80.4 of the report must describe the actions that the utility has 80.5 taken or will take to remedy the conditions responsible for each 80.6 listed circuit's unacceptable performance. The actions taken or 80.7 planned should be briefly described. Target dates for 80.8 corrective actions must be included in the report. When the 80.9 utility determines that actions on its part are unwarranted, its 80.10 report shall provide adequate justification for that conclusion. 80.11 (d) Utilities that use or prefer alternative criteria for 80.12 measuring individual circuit performance to those described in 80.13 paragraphs (b) and (c) and that are required by this section to 80.14 submit an annual report of reliability data, shall submit their 80.15 alternative listing of circuits along with the criteria used to 80.16 rank circuit performance. 80.17 (e) Information must be included with respect to any report 80.18 on the accomplishment of the improvements proposed in prior 80.19 reports for which completion has not been previously reported. 80.20 (f) The report must describe any new reliability or power 80.21 quality programs and changes that are made to existing programs. 80.22 (g) It must include a status report of any long-range 80.23 electric distribution plans. 80.24 (h) In addition to the information included in paragraph 80.25 (b), each utility that has the technical capability and 80.26 administrative resources shall report the following additional 80.27 service quality information: 80.28 (1) route miles of electric distribution line reconstructed 80.29 during the year, with separate totals for single- and 80.30 three-phase circuits provided; 80.31 (2) total route miles of electric distribution line in 80.32 service at year's end, segregated by voltage level; 80.33 (3) monthly average speed of answer for telephone calls 80.34 received regarding emergencies; 80.35 (4) the average number of calendar days a utility takes to 80.36 install and energize service to a customer site once it is ready 81.1 to receive service, with a separate average calculated for each 81.2 month, including all extensions energized during the calendar 81.3 month; 81.4 (5) the total number of written and telephone customer 81.5 complaints received in the areas of safety, outages, power 81.6 quality, customer property damage, and other areas, by month 81.7 filed; 81.8 (6) total annual tree-trimming budget and actual expenses; 81.9 and 81.10 (7) total annual projected and actual miles of tree-trimmed 81.11 distribution line. 81.12 Sec. 4. [216B.84] [INITIAL HISTORICAL RELIABILITY 81.13 PERFORMANCE REPORT.] 81.14 (a) Each electric utility with 6,000 retail customers or 81.15 more that has historically used measures of system, operating 81.16 area, and circuit reliability performance shall initially submit 81.17 annual system average interruption frequency index, system 81.18 average interruption duration index, and customer average 81.19 interruption duration index data for the previous three years. 81.20 Those utilities that have this data for some time period less 81.21 than three years shall submit data for those years it is 81.22 available. 81.23 (b) Those utilities whose historical reliability 81.24 performance data is similar or related to those measures listed 81.25 in paragraph (a), but differs due to how the parameters are 81.26 defined or calculated, shall submit the data it has and explain 81.27 any material differences from the prescribed indices. After the 81.28 effective date of this section, utilities shall modify their 81.29 reliability performance measures to conform to those specified 81.30 in sections 216B.80 to 216B.86 for purposes of consistent 81.31 reporting of comparable data in the future. 81.32 Sec. 5. [216B.85] [INTERRUPTIONS OF SERVICE; RECORDS; 81.33 NOTICE.] 81.34 Subdivision 1. [RECORDS.] (a) Each utility shall keep 81.35 records of all interruptions to service affecting the entire 81.36 distribution system of any single community or an important 82.1 division of a community, and include in the records each 82.2 interruption's location, date and time, and duration; the 82.3 approximate number of customers affected; the circuit or 82.4 circuits involved; and, when known, the cause of each 82.5 interruption. 82.6 (b) When complete distribution systems or portions of 82.7 communities have service furnished from unattended stations, 82.8 these records must be kept to the extent practicable. The 82.9 record of unattended stations shall show interruptions that 82.10 require attention to restore service, with the estimated time of 82.11 interruption. Breaker or fuse operations affecting service 82.12 should also be indicated even though duration of interruption 82.13 may not be known. 82.14 Subd. 2. [NOTICE OF INTERRUPTIONS OF BULK POWER SUPPLY 82.15 FACILITIES.] (a) Each utility owning or operating bulk power 82.16 supply facilities shall record any event described in clauses 82.17 (1) to (5) involving any generating unit or electric facilities 82.18 operating at a nominal voltage of 69 kilovolts or higher, and 82.19 shall make such records available to the commission 82.20 semi-annually or upon request of the commission: 82.21 (1) any interruption or loss of service to customers for 15 82.22 minutes or more to aggregate firm loads in excess of 200,000 82.23 kilowatts; 82.24 (2) any interruption or loss of service to customers for 15 82.25 minutes or more to aggregate firm loads exceeding the lesser of 82.26 100,000 kilowatts or one-half of the current annual system peak 82.27 load and not required recorded under clause (1); 82.28 (3) any decision to issue a public request for reduction in 82.29 use of electricity; 82.30 (4) an action to reduce firm customer loads by reduction of 82.31 voltage for reasons of maintaining adequacy of bulk electric 82.32 power supply; and 82.33 (5) any action to reduce firm customer loads by manual 82.34 switching, operation of automatic load-shedding devices, or any 82.35 other means for reasons of maintaining adequacy of bulk electric 82.36 power supply. 83.1 Subd. 3. [NOTICE OF OTHER INTERRUPTIONS OF POWER.] Each 83.2 utility shall record service interruptions of 60 minutes or more 83.3 to an entire distribution substation bus or entire feeder 83.4 serving either 500 or more customers or entire cities or 83.5 villages having 200 or more customers. 83.6 Subd. 4. [INFORMATION REQUIRED.] The written records 83.7 required in subdivisions 2 and 3 must include the date, time, 83.8 duration, general location, approximate number of customers 83.9 affected, identification of circuit or circuits involved, and, 83.10 when known, the cause of the interruption. When extensive 83.11 interruptions occur, as from a storm, a narrative record 83.12 including the extent of the interruptions and system damage, 83.13 estimated number of customers affected, and a list of entire 83.14 communities interrupted may be recorded in lieu of records of 83.15 individual interruptions. When customer service interruptions 83.16 are necessary, the utility shall make reasonable efforts to 83.17 notify affected customers in advance. 83.18 Sec. 6. [216B.86] [CUSTOMERS' COMPLAINTS.] 83.19 Each utility shall keep a record of complaints received by 83.20 it from its customers in regard to safety or service, and the 83.21 operation of its system, with appropriate response times 83.22 designated for critical safety and monetary loss situations and 83.23 shall investigate if appropriate. The record must show the name 83.24 and address of the complainant, the date and nature of the 83.25 complaint, the priority assigned to the assistance, and its 83.26 disposition and the time and date of its disposition. 83.27 Sec. 7. [216B.87] [STANDARDS FOR DISTRIBUTION UTILITIES.] 83.28 (a) The commission and each cooperative electric 83.29 association and municipal utility shall adopt standards for 83.30 safety, reliability, and service quality for distribution 83.31 utilities. Standards for cooperative electric associations and 83.32 municipal utilities should be as consistent as possible with the 83.33 commission standards. 83.34 (b) Reliability standards must be based on the system 83.35 average interruption frequency index, system average 83.36 interruption duration index, and customer average interruption 84.1 duration index measurement indices. Service quality standards 84.2 must specify, if technically and administratively feasible: 84.3 (1) average call center response time; 84.4 (2) customer disconnection rate; 84.5 (3) meter-reading frequency; 84.6 (4) complaint resolution response time; and 84.7 (5) service extension request response time. 84.8 (c) Minimum performance standards developed under this 84.9 section must treat similarly situated distribution systems 84.10 similarly and recognize differing characteristics of system 84.11 design and hardware. 84.12 (d) Electric distribution utilities shall comply with all 84.13 applicable governmental and industry standards required for the 84.14 safety, design, construction and operation of electric 84.15 distribution facilities, including section 326.243.