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Table of Sections

2013 Minnesota Statutes

Chapter 216B. Public Utilities

Chapter Sections
Section Headnote
216B.01Legislative Findings
216B.013Renumbered 216B.8109
216B.02Definitions
216B.022Submetering

MUNICIPALS, COOPERATIVES, DISTRIBUTION UTILITIES
216B.025Municipal Regulation Option
216B.026Cooperative Electric Association; Election on Regulation
216B.027Cooperative Electric Association Stockholder Rights
216B.029Standards for Distribution Utilities

RATES, STANDARDS, AND PRACTICES
216B.03Reasonable Rate
216B.04Standard of Service
216B.045Regulation of Intrastate Natural Gas Pipeline
216B.05Filing Schedules, Rules, and Service Agreements
216B.06Receiving Different Compensation
216B.07Rate Preference Prohibited
216B.075Meter Reading; Customer Scheduling Needs

COMMISSION RESPONSIBILITIES
216B.08Duties of Commission
216B.09Standards; Classifications; Rules; Practices

RESIDENTIAL PROTECTIONS; DISCONNECTION
216B.091Monthly Reports
216B.095Repealed, 2007 c 57 art 2 s 42,43
216B.0951Propane Prepurchase Program
216B.096Cold Weather Rule; Public Utility
216B.097Cold Weather Rule; Cooperative or Municipal Utility
216B.0975Disconnection during Extreme Heat Conditions
216B.0976Notice to Cities of Utility Disconnection
216B.098Residential Customer Protections

ACCOUNTING, MERCURY COSTS, DEPRECIATION
216B.10Accounting
216B.105Customer Share of Mercury Control Costs
216B.11Depreciation Rates and Practices

INVESTIGATORY REQUIREMENTS
216B.12Right of Entrance; Inspection
216B.13Production and Examination of Records
216B.14Investigation

RATE HEARINGS
216B.15Hearings; Examiner
216B.16Rate Change; Procedure; Hearing

SPECIAL RATES AND PRACTICES
216B.161Area Development Rate Plan
216B.1611Interconnection of on-Site Distributed Generation
216B.1612Community-Based Energy Development; Tariff
216B.1613Standardized Contract
216B.162Competitive Rate for Electric Utility
216B.1621Electric Service Agreement
216B.163Flexible Tariff
216B.1635Recovery of Gas Utility Infrastructure Costs
216B.1636Recovery of Electric Utility Infrastructure Costs
216B.1637Repealed, 2013 c 85 art 13 s 6
216B.164Cogeneration and Small Power Production
216B.1641Community Solar Garden
216B.1645Power Purchase Contract or Investment
216B.1646Rate Reduction; Property Tax Reduction
216B.165Repealed, 2007 c 136 art 3 s 7
216B.166Cogenerating Power Plant
216B.167Performance-Based Gas Purchasing Plan
216B.1675Performance Regulation Plan for Gas Utility Service
216B.168Expired, 1993 c 254 s 1
216B.1681Curtailment Payments
216B.169Renewable and High-Efficiency Energy Rate Options
216B.1691Renewable Energy Objectives
216B.1692Emissions-Reduction Rider
216B.1693MS 2010 Expired, 1Sp2003 c 11 art 2 s 4
216B.1694Innovative Energy Project
216B.1695Environmental Projects; Advance Determination of Prudence

COMPLAINTS AND HEARINGS
216B.17Complaint Investigation and Hearing
216B.18Service of Notice
216B.19Joint Hearing and Investigation
216B.20Separate Rate Hearing
216B.21Summary Investigation
216B.22Municipality; Amicus Curiae Authority
216B.23Lawful Rate; Reasonable Service

ENERGY CONSERVATION; UTILITY CONSTRUCTION
216B.24Construction of Major Facility; Filing Plans
216B.2401Energy Savings Policy Goal
216B.241Energy Conservation Improvement
216B.2411Distributed Energy Resources
216B.2412Decoupling of Energy Sales from Revenues
216B.242Repealed, 2011 c 97 s 34

RENEWABLE ENERGY INITIATIVES
216B.2421Definition of Large Energy Facility
216B.2422Resource Planning; Renewable Energy
216B.2423Wind Power Mandate
216B.2424Biomass Power Mandate
216B.2425State Transmission Plan
216B.2426Opportunities for Distributed Generation

CERTIFICATE OF NEED
216B.243Certificate of Need for Large Energy Facility

MISCELLANY
216B.244Nuclear Plant Capacity Requirements
216B.2445Decommissioning Nuclear Plant; Storing Used Fuel
216B.245Pump and Store Hydropower Facility; Prohibition
216B.246Federally Approved Transmission Lines; Incumbent Transmission Lineowner Rights

COMMISSION ORDERS; PROCEDURAL RESPONSIBILITIES
216B.25Further Action on Previous Order
216B.26Order; Effective Date
216B.27Rehearing; Condition Precedent to Judicial Review
216B.28Subpoena; Witness Fee and Mileage
216B.29Hearing and Subpoena Compliance Powers
216B.30Deposition
216B.31Testimony and Production of Records; Perjury
216B.32Certified Copy of Document As Evidence
216B.33Commission Ruling Written, Filed, and Certified
216B.34Public Records
216B.35Transcribed Record

MUNICIPAL POWERS
216B.36Municipal Regulatory and Taxing Powers

TOWNSHIP NATURAL GAS UTILITY AGREEMENT
216B.361Township Agreement with Natural Gas Utility

ASSIGNED ELECTRIC SERVICE AREAS
216B.37Assigned Service Area; Electric Utility; Legislative Policy
216B.38Definitions
216B.39Assigned Service Area
216B.40Exclusive Service Right; Service Extension
216B.41Effect of Incorporation, Annexation, or Consolidation
216B.42Service Extension in Certain Situations
216B.421Homestead; Option of Electric Service
216B.43Hearing on Complaint

MUNICIPAL ACQUISITION OF UTILITY PROPERTY
216B.44Municipal Service Territory Extension
216B.45Municipal Purchase of Public Utility
216B.46Municipal Acquisition Procedures; Notice; Election
216B.465Voter Ratification of Municipal Purchase, Limited Application
216B.47Acquisition by Eminent Domain

FINANCIAL ACTIVITIES AND BUSINESS PRACTICES
216B.48Relations with Affiliated Interest
216B.49Securities; Public Financing
216B.50Restrictions on Property Transfer and Merger
216B.51Stock Purchase

VIOLATIONS, PENALTIES, JUDICIAL CONSIDERATIONS
216B.52Appeal
216B.53Suspension of Commission Order
216B.54Legal Action Against Violation
216B.55Repealed, 1983 c 247 s 219
216B.56Burden of Proof
216B.57Penalty for Violation of Act
216B.58Penalties; Construing Act, Omission, and Failure
216B.59Continuing Violation
216B.60Penalties Cumulative
216B.61Actions to Recover Penalties

ASSESSMENTS
216B.62Regulatory Expenses
216B.63Interest on Assessment

MISCELLANEOUS
216B.64Attorney General's Responsibilities
216B.65Department to Employ Necessary Staff
216B.66Construction
216B.67Citation

MERCURY EMISSIONS REDUCTION
216B.68Definitions; Mercury Emissions Reduction
216B.681Monitoring Mercury Emissions
216B.682Mercury Emissions-Reduction Plans
216B.683Mercury Emissions Reduction; Cost Recovery, Financial Incentives
216B.684Environmental Assessment of Mercury Emissions-Reduction Plan
216B.685Mercury Emissions-Reduction Plan Approval
216B.6851Utility Option
216B.686Other Environmental Improvement Plans
216B.687Mercury Emissions Reduction Implementation, Operation
216B.688Relationship to Other State Financial Requirements

PREVENTATIVE MAINTENANCE
216B.79Preventative Maintenance
216B.81Renumbered 216B.029

HYDROGEN ENERGY
216B.8109Hydrogen Energy Economy Goal
216B.811Definitions
216B.812Fostering Use of Hydrogen Energy
216B.813Minnesota Renewable Hydrogen Initiative
216B.815Regional Energy Research and Education Partnership

LOCAL POWER QUALITY ZONES
216B.82Local Power Quality Zones

216B.01 LEGISLATIVE FINDINGS.

It is hereby declared to be in the public interest that public utilities be regulated as hereinafter provided in order to provide the retail consumers of natural gas and electric service in this state with adequate and reliable services at reasonable rates, consistent with the financial and economic requirements of public utilities and their need to construct facilities to provide such services or to otherwise obtain energy supplies, to avoid unnecessary duplication of facilities which increase the cost of service to the consumer and to minimize disputes between public utilities which may result in inconvenience or diminish efficiency in service to the consumers. Because municipal utilities are presently effectively regulated by the residents of the municipalities which own and operate them, and cooperative electric associations are presently effectively regulated and controlled by the membership under the provisions of chapter 308A, it is deemed unnecessary to subject such utilities to regulation under this chapter except as specifically provided herein.

216B.013 [Renumbered 216B.8109]

216B.02 DEFINITIONS.

Subdivision 1.Scope.

For the purposes of this chapter, the terms defined in this section have the meanings given them.

Subd. 1a.Commission.

"Commission" means the Public Utilities Commission.

Subd. 1b.Commissioner.

"Commissioner" means the commissioner of the Minnesota Department of Commerce.

Subd. 2.Corporation.

"Corporation" means a private corporation, a public corporation, a municipality, an association, a cooperative whether incorporated or not, a joint stock association, a business trust, or any political subdivision or agency.

Subd. 2a.Department.

"Department" means the Department of Commerce of the state of Minnesota.

Subd. 2b.Municipality.

"Municipality" means any city however organized.

Subd. 3.Person.

"Person" means a natural person, a partnership, or two or more persons having a joint or common interest, and a corporation as hereinbefore defined.

Subd. 4.Public utility.

"Public utility" means persons, corporations, or other legal entities, their lessees, trustees, and receivers, now or hereafter operating, maintaining, or controlling in this state equipment or facilities for furnishing at retail natural, manufactured, or mixed gas or electric service to or for the public or engaged in the production and retail sale thereof but does not include (1) a municipality or a cooperative electric association, organized under the provisions of chapter 308A, producing or furnishing natural, manufactured, or mixed gas or electric service; (2) a retail seller of compressed natural gas used as a vehicular fuel which purchases the gas from a public utility; or (3) a retail seller of electricity used to recharge a battery that powers an electric vehicle, as defined in section 169.011, subdivision 26a, and that is not otherwise a public utility under this chapter. Except as otherwise provided, the provisions of this chapter shall not be applicable to any sale of natural, manufactured, or mixed gas or electricity by a public utility to another public utility for resale. In addition, the provisions of this chapter shall not apply to a public utility whose total natural gas business consists of supplying natural, manufactured, or mixed gas to not more than 650 customers within a city pursuant to a franchise granted by the city, provided a resolution of the city council requesting exemption from regulation is filed with the commission. The city council may rescind the resolution requesting exemption at any time, and, upon the filing of the rescinding resolution with the commission, the provisions of this chapter shall apply to the public utility. No person shall be deemed to be a public utility if it furnishes its services only to tenants or cooperative or condominium owners in buildings owned, leased, or operated by such person. No person shall be deemed to be a public utility if it furnishes service to occupants of a manufactured home or trailer park owned, leased, or operated by such person. No person shall be deemed to be a public utility if it produces or furnishes service to less than 25 persons.

Subd. 5.Rate.

"Rate" means every compensation, charge, fare, toll, tariff, rental, and classification, or any of them, demanded, observed, charged, or collected by any public utility for any service and any rules, practices, or contracts affecting any such compensation, charge, fare, toll, rental, tariff, or classification.

Subd. 6.Service.

"Service" means natural, manufactured, or mixed gas and electricity; the installation, removal, or repair of equipment or facilities for delivering or measuring such gas and electricity.

Subd. 6a.Submetering.

"Submetering" means measuring, by a building's owner, through mechanical or electronic devices, the use of electricity by occupants in multiple-unit residential or commercial buildings to fairly apportion the entire electrical costs for the building among its occupants.

Subd. 7.

[Renumbered subd 1a]

Subd. 8.

[Renumbered subd 2a]

Subd. 9.

[Renumbered subd 2b]

Subd. 10.Transmission company.

"Transmission company" means persons, corporations, or other legal entities and their lessees, trustees, and receivers, engaged in the business of owning, operating, maintaining, or controlling in this state equipment or facilities for furnishing electric transmission service in Minnesota, but does not include public utilities, municipal electric utilities, municipal power agencies, cooperative electric associations, or generation and transmission cooperative power associations.

216B.022 SUBMETERING.

Nothing in this chapter grants the commission or a public utility the authority to limit the availability of submetering to a building occupant when the building is served by a public utility's master meter which measures the total electric energy delivered to the building.

History:

1983 c 366 s 3


MUNICIPALS, COOPERATIVES, DISTRIBUTION UTILITIES

216B.025 MUNICIPAL REGULATION OPTION.

A municipality may elect to become subject to regulation by the commission pursuant to sections 216B.10 and 216B.11. An election for regulation may be effected by resolution of the governing body requesting regulation and filed with the commission.

History:

1981 c 142 s 1

216B.026 COOPERATIVE ELECTRIC ASSOCIATION; ELECTION ON REGULATION.

Subdivision 1.Election.

A cooperative electric association may elect to become subject to rate regulation by the commission pursuant to sections 216B.03 to 216B.23. The election shall be approved by a majority of members or stockholders voting by mail ballot initiated by petition of not less than five percent of the members or stockholders of the association, as determined by membership figures submitted by the association to the Rural Electric Administration for the month in which the petition was submitted.

Subd. 2.Petition contents; verification.

The petition form shall be prescribed by the department and sample forms shall be available from the department and electric cooperative associations. Petitions shall include a uniform statement that petition signers are requesting a balloting of the association membership on the question of regulation of electric rates of the association by the commission. The department shall, upon receipt, transmit the prescribed form of petition to the appropriate association for validation of petition signatures in accordance with agreed procedures between the association and the department. When the association rejects any signature on a petition as invalid, it shall provide the department with a written statement as to the reason the cooperative deems the signature invalid. The department may challenge the association's decisions on the validity of signatures and may appeal to the commission for a resolution of the issue through informal proceedings before the commission after notice to all parties.

Subd. 3.Voting for members.

Whenever a vote or petition of members or stockholders of an association is submitted pursuant to this section, the spouse of the member or stockholder may sign the petition and vote on behalf of the member or stockholder unless the member or stockholder has notified the association in writing otherwise. Such a notification by a member or stockholder shall be provided to the association and to the department for those petition matters pursuant to this section.

Subd. 4.Election procedure; effect.

If the department determines that the petition meets the percent requirement of subdivision 1, a balloting of members on the question of regulation of electric rates by the commission shall be supervised by the department. The ballot to be used for the election shall be approved by the board of directors of the association and the department. In the event of a dispute on balloting procedures, the dispute shall be resolved through informal proceedings before the commission after notice to all parties. The association shall mail ballots to the association's members who shall return the ballots to the department. The department shall keep the ballots sealed until a date agreed upon by the department and the board of directors. On this date, representatives of the department and the association shall count the ballots. If a majority of the association's members or spouses who vote, elect to become subject to rate regulation by the commission, the election shall be effective 30 days after certified copies of the resolutions approving the election are filed with the commission. These provisions also apply to associations that wish to be deregulated. Any cooperative that is regulated by the commission, pursuant to sections 216B.03 to 216B.23 may follow the procedures set forth above. Any association subject to regulation of rates by the commission shall be exempt from the provisions of sections 216B.48, 216B.49, 216B.50, and 216B.51.

Subd. 5.Member due process.

Section 216B.027, granting rights to stockholders, applies to the exercise of stockholders' rights regardless of whether a referendum has been held as required by section 216B.027, subdivision 7. Notwithstanding section 216B.027, subdivision 6, a cooperative shall pay the costs of including stockholders' positions on issues as provided under section 216B.027, subdivision 6. This subdivision applies only to elections that require no less than one percent of members to initiate pursuant to subdivision 1.

216B.027 COOPERATIVE ELECTRIC ASSOCIATION STOCKHOLDER RIGHTS.

Subdivision 1.Intent.

It is the intent of this section to specify those rights which shall be extended to stockholders of cooperative electric associations. The guarantee of these rights, as specified herein, is intended to further the active participation of stockholders in any and all matters pertaining to the prudent operation of their organization.

Subd. 2.Scope.

Cooperative associations organized under chapter 308A for the purpose of providing rural electrification at retail to ultimate consumers shall comply with the provisions of this section in addition to other applicable provisions of chapter 308A and other applicable state and federal laws.

Subd. 3.Business records.

The provisions of section 302A.461 and any amendments or successor requirements to it shall apply to every wholesale or retail cooperative electric association. The rights granted to wholesale and retail electric cooperative stockholders in this section shall apply also to the spouse of the stockholder. In addition to the requirements of section 302A.461, a wholesale or retail electric cooperative shall maintain records of all proceedings of meetings of stockholders and directors during the previous three-year period including the vote of each director on roll call votes. Roll call votes are required on actions which directly establish service charge and rate schedules. Roll call voting is also required on any matter upon the request of one or more directors. Every duly elected director of a retail cooperative electric association shall have the right to inspect under section 302A.461, in person and at any reasonable time, the business records required by this subdivision and maintained by the wholesale cooperative electric association from which it purchases the majority of its electric requirements.

Subd. 4.Open meeting; notice.

Meetings of the board of directors of any retail cooperative electric association must be open to the stockholders of the cooperative and the stockholders' spouses. Stockholders must be given notice of all regularly scheduled meetings except those of an emergency nature. Duly elected directors of retail cooperative associations must be given notice, through their retail cooperative associations, of all meetings of the board of directors of the wholesale cooperative association, except those of an emergency nature, from which the retail cooperative purchases the majority of its electric requirements. Portions of meetings relating to labor negotiations, current litigation, personnel matters, and nonpayment of customer accounts are excluded from the provisions of this subdivision.

Subd. 5.Petitions; voting.

Notwithstanding the provisions of sections 308A.611 and 308A.615, upon receipt of a written petition concerning governance matters signed by at least 500 stockholders or five percent of the stockholders, whichever is less, of a retail cooperative electric association, the matter in the petition must be presented to the stockholders of the cooperative for a vote at the next annual meeting. Petitions must be received by the cooperative electric association 60 days prior to the scheduled annual meeting. For purposes of this section, "governance matters" means matters properly contained in the articles of incorporation or bylaws by adopting, amending, or repealing bylaws or the articles of incorporation.

Subd. 6.Equal time; petitioner.

Whenever the directors of a retail cooperative electric association provide information to stockholders to influence their vote on a matter to be decided by a vote of the stockholders pursuant to a successful petition submitted under the provisions of subdivision 5 or section 216B.026, subdivision 4, the directors shall provide the organizers of the petition or person presenting the petition the opportunity to include their position on the matter to the stockholders in a substantially similar mode and range of distribution. The organizers of the petition shall pay the costs of such inclusion.

Subd. 7.Optional referendum.

No cooperative shall be bound by the provisions of this section unless adoption has been approved at referendum using the petition and election procedures in section 216B.026. Within 60 days of May 19, 1983, the board of directors of each cooperative electric association shall notify the stockholders of the provisions of this section and shall explain the process for ratification by petition and election as provided in this subdivision.

216B.029 STANDARDS FOR DISTRIBUTION UTILITIES.

Subdivision 1.Standards.

(a) The commission and each cooperative electric association and municipal utility shall adopt standards for safety, reliability, and service quality for distribution utilities. Standards for cooperative electric associations and municipal utilities should be as consistent as possible with the commission standards.

(b) Reliability standards must be based on the system average interruption frequency index, system average interruption duration index, and customer average interruption duration index measurement indices. Service quality standards must specify, if technically and administratively feasible:

(1) average call center response time;

(2) customer disconnection rate;

(3) meter-reading frequency;

(4) complaint resolution response time;

(5) service extension request response time;

(6) recording of service and circuit interrupter data;

(7) summary reporting;

(8) historical reliability performance reporting;

(9) notices of interruptions of bulk power supply facilities and other interruptions of power; and

(10) customer complaints.

(c) Minimum performance standards developed under this section must treat similarly situated distribution systems similarly and recognize differing characteristics of system design and hardware.

(d) Electric distribution utilities shall comply with all applicable governmental and industry standards required for the safety, design, construction, and operation of electric distribution facilities, including section 326B.35.

Subd. 2.Definitions.

For the purpose of this section, the terms defined in this subdivision have the meanings given them.

(a) The "system average interruption frequency index" is the average number of interruptions per customer per year. It is determined by dividing the total annual number of customer interruptions by the average number of customers served during the year.

(b) The "system average interruption duration index" is the average customer-minutes of interruption per customer. It is determined by dividing the annual sum of customer-minutes of interruption by the average number of customers served during the year.

(c) The "customer average interruption duration index" is the average customer-minutes of interruption per customer interruption. It approximates the average length of time required to complete service restoration. It is determined by dividing the annual sum of all customer-minutes of interruption durations by the annual number of customer interruptions.

History:

2001 c 212 art 6 s 1; 2007 c 140 art 5 s 32; art 13 s 4


RATES, STANDARDS, AND PRACTICES

216B.03 REASONABLE RATE.

Every rate made, demanded, or received by any public utility, or by any two or more public utilities jointly, shall be just and reasonable. Rates shall not be unreasonably preferential, unreasonably prejudicial, or discriminatory, but shall be sufficient, equitable, and consistent in application to a class of consumers. To the maximum reasonable extent, the commission shall set rates to encourage energy conservation and renewable energy use and to further the goals of sections 216B.164, 216B.241, and 216C.05. Any doubt as to reasonableness should be resolved in favor of the consumer. For rate-making purposes a public utility may treat two or more municipalities served by it as a single class wherever the populations are comparable in size or the conditions of service are similar.

216B.04 STANDARD OF SERVICE.

Every public utility shall furnish safe, adequate, efficient, and reasonable service; provided that service shall be deemed adequate if made so within 90 days after a person requests service. Upon application by a public utility, and for good cause shown, the commission may extend the period for not to exceed another 90 days.

History:

1974 c 429 s 4

216B.045 REGULATION OF INTRASTATE NATURAL GAS PIPELINE.

Subdivision 1.Definition of intrastate pipeline.

For the purposes of this section "intrastate pipeline" means a pipeline wholly within the state of Minnesota which transports or delivers natural gas received from another person at a point inside or at the border of the state, which is delivered at a point within the state to another, provided that all the natural gas is consumed within the state. An intrastate pipeline does not include a pipeline owned or operated by a public utility, unless a public utility files a petition requesting that a pipeline or a portion of a pipeline be classified as an intrastate pipeline and the commission approves the petition.

Subd. 2.Reasonable rate.

Every rate and contract relating to the sale or transportation of natural gas through an intrastate pipeline shall be just and reasonable. No owner or operator of an intrastate pipeline shall provide intrastate pipeline services in a manner which unreasonably discriminates among customers receiving like or contemporaneous services.

Subd. 3.Transportation rate; discrimination.

Every owner or operator of an intrastate pipeline shall offer intrastate pipeline transportation services by contract on an open access, nondiscriminatory basis. To the extent the intrastate pipeline has available capacity, the owner or operator of the intrastate pipeline must provide firm and interruptible transportation on behalf of any customer. If physical facilities are needed to establish service to a customer, the customer may provide those facilities or the owner or operator of the intrastate pipeline may provide the facilities for a reasonable and compensatory charge.

Subd. 4.Contract; commission approval.

No contract establishing the rates, terms, and conditions of service and facilities to be provided by intrastate pipelines is effective until it is filed with and approved by the commission. The commission has the authority to approve the contracts and to regulate the types and quality of services to be provided through intrastate pipelines. The approval of a contract for an intrastate pipeline to provide service to a public utility does not constitute a determination by the commission that the prices actually paid by the public utility under that contract are reasonable or prudent nor does approval constitute a determination that purchases of gas made or deliveries of gas taken by the public utility under that contract are reasonable or prudent.

Subd. 5.Complaint.

Any customer of an intrastate pipeline, any person seeking to become a customer of an intrastate pipeline, the department, or the commission on its own motion, may bring a complaint regarding the rates, contracts, terms, conditions, and types of service provided or proposed to be provided through an intrastate pipeline, including a complaint that a service which can reasonably be demanded is not offered by the owner or operator of the intrastate pipeline. If a complaint involves the question of whether or not an intrastate pipeline has capacity available, the commission shall after hearing make a determination of the available capacity but shall not impair the owner or operator of the intrastate pipeline contractual obligation to provide firm transportation service. If a complaint concerns the use of available capacity by one or more customers of an intrastate pipeline, the commission shall after hearing determine the reasonable use of the available capacity by the customers. The commission shall not require an owner or operator of an intrastate pipeline to expand its available capacity but may require the owner or operator to maintain a reasonable quality of service. The commission may dismiss any complaint without a hearing if in its opinion a hearing is not in the public interest. Complaints brought under this subdivision shall be governed by section 216B.17.

Subd. 6.Records; reports; inspections; cost assessments.

Sections 216B.10, subdivisions 1 and 4, 216B.12, 216B.13, and 216B.62, subdivisions 2, 4, and 6, shall apply to owners and operators of intrastate pipelines.

Subd. 7.Natural gas emergency.

The commission may declare a natural gas supply emergency if it finds that a severe natural gas shortage endangering the health or safety of the citizens of the state exists or is imminent in the state. If the commission declares that a natural gas supply emergency exists, it may for the duration of the emergency order the suspension of any contract providing for the sale and transportation of natural gas through an intrastate pipeline, and may for the duration of the emergency order an owner or operator of the intrastate pipeline to furnish such transportation services as are required by the public interest. The owner or operator of the intrastate pipeline shall be compensated for its services furnished under an emergency order issued under this section, and the commission shall determine the just and reasonable compensation for the services required to be provided during the emergency.

216B.05 FILING SCHEDULES, RULES, AND SERVICE AGREEMENTS.

Subdivision 1.Public rate filing.

Every public utility shall file with the commission schedules showing all rates, tolls, tariffs, and charges which it has established and which are in force at the time for any service performed by it within the state, or for any service in connection therewith or performed by any public utility controlled or operated by it.

Subd. 2.Schedule and rules filing.

Every public utility shall file with and as a part of the filings under subdivision 1, all rules that, in the judgment of the commission, in any manner affect the service or product, or the rates charged or to be charged for any service or product, as well as any contracts, agreements, or arrangements relating to the service or product or the rates to be charged for any service or product to which the schedule is applicable as the commission may by general or special order direct; provided that contracts and agreements for electric service must be filed as required by subdivision 2a.

Subd. 2a.Electric service contract.

A contract for electric service entered into between a public utility and one of its customers, in which the public utility and the customer agree to customer-specific rates, terms, or service conditions not already contained in the approved schedules, tariffs, or rules of the utility, must be filed for approval by the commission pursuant to the commission's rules of practice. Contracts between public utilities and customers that are necessitated by specific statutes in this chapter must be filed for approval under those statutes and any rules adopted by the commission pursuant to those statutes.

Subd. 3.Public inspection.

Every public utility shall keep copies of the filings under subdivisions 1, 2, and 2a open to public inspection under rules as the commission may prescribe.

216B.06 RECEIVING DIFFERENT COMPENSATION.

No public utility shall directly or indirectly, by any device whatsoever, or in any manner, charge, demand, collect, or receive from any person a greater or less compensation for any service rendered or to be rendered by the utility than that prescribed in the schedules of rates of the public utility applicable thereto when filed in the manner provided in Laws 1974, chapter 429, nor shall any person knowingly receive or accept any service from a public utility for a compensation greater or less than that prescribed in the schedules, provided that all rates being charged and collected by a public utility upon January 1, 1975, may be continued until schedules are filed.

216B.07 RATE PREFERENCE PROHIBITED.

No public utility shall, as to rates or service, make or grant any unreasonable preference or advantage to any person or subject any person to any unreasonable prejudice or disadvantage.

History:

1974 c 429 s 7

216B.075 METER READING; CUSTOMER SCHEDULING NEEDS.

Notwithstanding any other provision of rule or policy to the contrary, every public utility providing natural gas or electricity at retail shall make a reasonable effort to obtain readings at least once every 18 months from nonaccessible meters. Readings shall be obtained at times that meet the needs of customer schedules. Utilities shall make a reasonable effort to provide evening and Saturday or Sunday meter reading service at no extra charge to a customer whose work or other schedule makes a business hour reading of meters a hardship. Utilities may refuse to read a customer's meter during nondaylight hours if such activity could threaten the safety of the utility meter-reading employee.

A utility may also allow a customer to self-read the customer's meter for periods of time not to exceed 18 months, provided that the customer is reminded periodically of the potentially serious financial consequences of errors in self-reading.

A utility may terminate service to a customer who refuses to allow a utility company employee access to a nonaccessible meter for a period of 18 months or more.

History:

1983 c 176 s 1


COMMISSION RESPONSIBILITIES

216B.08 DUTIES OF COMMISSION.

The commission is hereby vested with the powers, rights, functions, and jurisdiction to regulate in accordance with the provisions of Laws 1974, chapter 429 every public utility as defined herein. The exercise of such powers, rights, functions, and jurisdiction is prescribed as a duty of the commission. The commission is authorized to make rules in furtherance of the purposes of Laws 1974, chapter 429.

216B.09 STANDARDS; CLASSIFICATIONS; RULES; PRACTICES.

Subdivision 1.Commission authority, generally.

The commission, on its own motion or upon complaint and after reasonable notice and hearing, may ascertain and fix just and reasonable standards, classifications, rules, or practices to be observed and followed by any or all public utilities with respect to the service to be furnished.

Subd. 2.Electric service, rules, measurement standards, grounding.

The commission, on its own motion or upon complaint and after reasonable notice and hearing, may ascertain and fix adequate and reasonable standards for the measurement of the quantity, quality, pressure, initial voltage, or other condition pertaining to the supply of the service; prescribe reasonable rules for the examination and testing of the service and for the measurement thereof; establish or approve reasonable rules, specifications, and standards to secure the accuracy of all meters, instruments, and equipment used for the measurement of any service of any public utility. In this subdivision, service standards or requirements governing any current or voltage originating from the practice of grounding of electrical systems apply to cooperative associations and municipal utilities providing or furnishing retail electric service to agricultural customers.

Subd. 3.Filings.

Any standards, classifications, rules, or practices now or hereafter observed or followed by any public utility may be filed by it with the commission, and the same shall continue in force until amended by the public utility or until changed by the commission as herein provided.

The commission may require the filing of all rates, including rates charged to and by public utilities.

Subd. 4.Appearance before federal agency.

The commission is empowered to appear before the Federal Energy Regulatory Commission to offer evidence and to seek appropriate relief in any case in which the rates charged consumers within the state of Minnesota may be affected.


RESIDENTIAL PROTECTIONS; DISCONNECTION

216B.091 MONTHLY REPORTS.

(a) Each public utility must report the following data on residential customers to the commission monthly, in a format determined by the commission:

(1) number of customers;

(2) number and total amount of accounts past due;

(3) average customer past due amount;

(4) total revenue received from the low-income home energy assistance program and other sources contributing to the bills of low-income persons;

(5) average monthly bill;

(6) total sales revenue;

(7) total write-offs due to uncollectible bills;

(8) number of disconnection notices mailed;

(9) number of accounts disconnected for nonpayment;

(10) number of accounts reconnected to service; and

(11) number of accounts that remain disconnected, grouped by the duration of disconnection, as follows:

(i) 1-30 days;

(ii) 31-60 days; and

(iii) more than 60 days.

(b) Monthly reports for October through April must also include the following data:

(1) number of cold weather protection requests;

(2) number of payment arrangement requests received and granted;

(3) number of right to appeal notices mailed to customers;

(4) number of reconnect request appeals withdrawn;

(5) number of occupied heat-affected accounts disconnected for 24 hours or more for electric and natural gas service separately;

(6) number of occupied non-heat-affected accounts disconnected for 24 hours or more for electric and gas service separately;

(7) number of customers granted cold weather rule protection;

(8) number of customers disconnected who did not request cold weather rule protection; and

(9) number of customers disconnected who requested cold weather rule protection.

(c) The data reported under paragraphs (a) and (b) is presumed to be accurate upon submission and must be made available through the commission's electronic filing system. A monthly report must be filed with the commission no later than 45 days after the last day of the month for which data is reported.

216B.095 [Repealed, 2007 c 57 art 2 s 42,43]

216B.0951 PROPANE PREPURCHASE PROGRAM.

Subdivision 1.Establishment.

The commissioner of commerce shall operate, or contract to operate, a propane fuel prepurchase fuel program. The commissioner may contract at any time of the year to purchase the lesser of one-third of the liquid propane fuel consumed by low-income home energy assistance program recipients during the previous heating season or the amount that can be purchased with available funds. The propane fuel prepurchase program must be available statewide through each local agency that administers the energy assistance program. The commissioner may decide to limit or not engage in prepurchasing if the commissioner finds that there is a reasonable likelihood that prepurchasing will not provide fuel-cost savings.

Subd. 2.Hedge account.

The commissioner may establish a hedge account with realized program savings due to prepurchasing. The account must be used to compensate program recipients an amount up to the difference in cost for fuel provided to the recipient if winter-delivered fuel prices are lower than the prepurchase or summer-fill price. No more than ten percent of the aggregate prepurchase program savings may be used to establish the hedge account.

Subd. 3.Report.

The Department of Commerce shall issue a report by June 30, 2008, made available electronically on its Web site and in print upon request, that contains the following information:

(1) the cost per gallon of prepurchased fuel;

(2) the total gallons of fuel prepurchased;

(3) the average cost of propane each month between October and the following April;

(4) the number of energy assistance program households receiving prepurchased fuel; and

(5) the average savings accruing or benefit increase provided to energy assistance households.

216B.096 COLD WEATHER RULE; PUBLIC UTILITY.

Subdivision 1.Scope.

This section applies only to residential customers of a utility.

Subd. 2.Definitions.

(a) The terms used in this section have the meanings given them in this subdivision.

(b) "Cold weather period" means the period from October 15 through April 15 of the following year.

(c) "Customer" means a residential customer of a utility.

(d) "Disconnection" means the involuntary loss of utility heating service as a result of a physical act by a utility to discontinue service. Disconnection includes installation of a service or load limiter or any device that limits or interrupts utility service in any way.

(e) "Household income" means the combined income, as defined in section 290A.03, subdivision 3, of all residents of the customer's household, computed on an annual basis. Household income does not include any amount received for energy assistance.

(f) "Reasonably timely payment" means payment within five working days of agreed-upon due dates.

(g) "Reconnection" means the restoration of utility heating service after it has been disconnected.

(h) "Summary of rights and responsibilities" means a commission-approved notice that contains, at a minimum, the following:

(1) an explanation of the provisions of subdivision 5;

(2) an explanation of no-cost and low-cost methods to reduce the consumption of energy;

(3) a third-party notice;

(4) ways to avoid disconnection;

(5) information regarding payment agreements;

(6) an explanation of the customer's right to appeal a determination of income by the utility and the right to appeal if the utility and the customer cannot arrive at a mutually acceptable payment agreement; and

(7) a list of names and telephone numbers for county and local energy assistance and weatherization providers in each county served by the utility.

(i) "Third-party notice" means a commission-approved notice containing, at a minimum, the following information:

(1) a statement that the utility will send a copy of any future notice of proposed disconnection of utility heating service to a third party designated by the residential customer;

(2) instructions on how to request this service; and

(3) a statement that the residential customer should contact the person the customer intends to designate as the third-party contact before providing the utility with the party's name.

(j) "Utility" means a public utility as defined in section 216B.02, and a cooperative electric association electing to be a public utility under section 216B.026. Utility also means a municipally owned gas or electric utility for nonresident consumers of the municipally owned utility and a cooperative electric association when a complaint in connection with utility heating service during the cold weather period is filed under section 216B.17, subdivision 6 or 6a.

(k) "Utility heating service" means natural gas or electricity used as a primary heating source, including electricity service necessary to operate gas heating equipment, for the customer's primary residence.

(l) "Working days" means Mondays through Fridays, excluding legal holidays. The day of receipt of a personally served notice and the day of mailing of a notice shall not be counted in calculating working days.

Subd. 3.Utility obligations before cold weather period.

Each year, between September 1 and October 15, each utility must provide all customers, personally, by first class mail, or electronically for those requesting electronic billing, a summary of rights and responsibilities. The summary must also be provided to all new residential customers when service is initiated.

Subd. 4.Notice before disconnection during cold weather period.

Before disconnecting utility heating service during the cold weather period, a utility must provide, personally or by first class mail, a commission-approved notice to a customer, in easy-to-understand language, that contains, at a minimum, the date of the scheduled disconnection, the amount due, and a summary of rights and responsibilities.

Subd. 5.Cold weather rule.

(a) During the cold weather period, a utility may not disconnect and must reconnect utility heating service of a customer whose household income is at or below 50 percent of the state median income if the customer enters into and makes reasonably timely payments under a mutually acceptable payment agreement with the utility that is based on the financial resources and circumstances of the household; provided that, a utility may not require a customer to pay more than ten percent of the household income toward current and past utility bills for utility heating service.

(b) A utility may accept more than ten percent of the household income as the payment arrangement amount if agreed to by the customer.

(c) The customer or a designated third party may request a modification of the terms of a payment agreement previously entered into if the customer's financial circumstances have changed or the customer is unable to make reasonably timely payments.

(d) The payment agreement terminates at the expiration of the cold weather period unless a longer period is mutually agreed to by the customer and the utility.

(e) Each utility shall use reasonable efforts to restore service within 24 hours of an accepted payment agreement, taking into consideration customer availability, employee availability, and construction-related activity.

Subd. 6.Verification of income.

(a) In verifying a customer's household income, a utility may:

(1) accept the signed statement of a customer that the customer is income eligible;

(2) obtain income verification from a local energy assistance provider or a government agency;

(3) consider one or more of the following:

(i) the most recent income tax return filed by members of the customer's household;

(ii) for each employed member of the customer's household, paycheck stubs for the last two months or a written statement from the employer reporting wages earned during the preceding two months;

(iii) documentation that the customer receives a pension from the Department of Human Services, the Social Security Administration, the Veteran's Administration, or other pension provider;

(iv) a letter showing the customer's dismissal from a job or other documentation of unemployment; or

(v) other documentation that supports the customer's declaration of income eligibility.

(b) A customer who receives energy assistance benefits under any federal, state, or county government programs in which eligibility is defined as household income at or below 50 percent of state median income is deemed to be automatically eligible for protection under this section and no other verification of income may be required.

Subd. 7.Prohibitions and requirements.

(a) This subdivision applies during the cold weather period.

(b) A utility may not charge a deposit or delinquency charge to a customer who has entered into a payment agreement or a customer who has appealed to the commission under subdivision 8.

(c) A utility may not disconnect service during the following periods:

(1) during the pendency of any appeal under subdivision 8;

(2) earlier than ten working days after a utility has deposited in first class mail, or seven working days after a utility has personally served, the notice required under subdivision 4 to a customer in an occupied dwelling;

(3) earlier than ten working days after the utility has deposited in first class mail the notice required under subdivision 4 to the recorded billing address of the customer, if the utility has reasonably determined from an on-site inspection that the dwelling is unoccupied;

(4) on a Friday, unless the utility makes personal contact with, and offers a payment agreement consistent with this section to the customer;

(5) on a Saturday, Sunday, holiday, or the day before a holiday;

(6) when utility offices are closed;

(7) when no utility personnel are available to resolve disputes, enter into payment agreements, accept payments, and reconnect service; or

(8) when commission offices are closed.

(d) A utility may not discontinue service until the utility investigates whether the dwelling is actually occupied. At a minimum, the investigation must include one visit by the utility to the dwelling during normal working hours. If no contact is made and there is reason to believe that the dwelling is occupied, the utility must attempt a second contact during nonbusiness hours. If personal contact is made, the utility representative must provide notice required under subdivision 4 and, if the utility representative is not authorized to enter into a payment agreement, the telephone number the customer can call to establish a payment agreement.

(e) Each utility must reconnect utility service if, following disconnection, the dwelling is found to be occupied and the customer agrees to enter into a payment agreement or appeals to the commission because the customer and the utility are unable to agree on a payment agreement.

Subd. 8.Disputes; customer appeals.

(a) A utility must provide the customer and any designated third party with a commission-approved written notice of the right to appeal:

(1) a utility determination that the customer's household income is more than 50 percent of state median household income; or

(2) when the utility and customer are unable to agree on the establishment or modification of a payment agreement.

(b) A customer's appeal must be filed with the commission no later than seven working days after the customer's receipt of a personally served appeal notice, or within ten working days after the utility has deposited a first class mail appeal notice.

(c) The commission must determine all customer appeals on an informal basis, within 20 working days of receipt of a customer's written appeal. In making its determination, the commission must consider one or more of the factors in subdivision 6.

(d) Notwithstanding any other law, following an appeals decision adverse to the customer, a utility may not disconnect utility heating service for seven working days after the utility has personally served a disconnection notice, or for ten working days after the utility has deposited a first class mail notice. The notice must contain, in easy-to-understand language, the date on or after which disconnection will occur, the reason for disconnection, and ways to avoid disconnection.

Subd. 9.Cooperative and municipal disputes.

Complaints in connection with utility heating service during the cold weather period filed against a municipal or a cooperative electric association with the commission under section 216B.17, subdivision 6 or 6a, are governed by section 216B.097.

Subd. 10.Customers above 50 percent of state median income.

During the cold weather period, a customer whose household income is above 50 percent of state median income:

(1) has the right to a payment agreement that takes into consideration the customer's financial circumstances and any other extenuating circumstances of the household; and

(2) may not be disconnected and must be reconnected if the customer makes timely payments under a payment agreement accepted by a utility.

Subdivision 7, paragraph (b), does not apply to customers whose household income is above 50 percent of state median income.

Subd. 11.Reporting.

Annually on November 1, a utility must electronically file with the commission a report, in a format specified by the commission, specifying the number of utility heating service customers whose service is disconnected or remains disconnected for nonpayment as of October 1 and October 15. If customers remain disconnected on October 15, a utility must file a report each week between November 1 and the end of the cold weather period specifying:

(1) the number of utility heating service customers that are or remain disconnected from service for nonpayment; and

(2) the number of utility heating service customers that are reconnected to service each week. The utility may discontinue weekly reporting if the number of utility heating service customers that are or remain disconnected reaches zero before the end of the cold weather period.

The data reported under this subdivision are presumed to be accurate upon submission and must be made available through the commission's electronic filing system.

History:

2007 c 57 art 2 s 13,43; 2008 c 162 s 2,3; 2011 c 97 s 7

216B.097 COLD WEATHER RULE; COOPERATIVE OR MUNICIPAL UTILITY.

Subdivision 1.Application; notice to residential customer.

(a) A municipal utility or a cooperative electric association must not disconnect and must reconnect the utility service of a residential customer during the period between October 15 and April 15 if the disconnection affects the primary heat source for the residential unit and all of the following conditions are met:

(1) The household income of the customer is at or below 50 percent of the state median household income. A municipal utility or cooperative electric association utility may (i) verify income on forms it provides or (ii) obtain verification of income from the local energy assistance provider. A customer is deemed to meet the income requirements of this clause if the customer receives any form of public assistance, including energy assistance, that uses an income eligibility threshold set at or below 50 percent of the state median household income.

(2) A customer enters into and makes reasonably timely payments under a payment agreement that considers the financial resources of the household.

(3) A customer receives referrals to energy assistance, weatherization, conservation, or other programs likely to reduce the customer's energy bills.

(b) A municipal utility or a cooperative electric association must, between August 15 and October 15 each year, notify all residential customers of the provisions of this section.

Subd. 2.Notice to residential customer facing disconnection.

Before disconnecting service to a residential customer during the period between October 15 and April 15, a municipal utility or cooperative electric association must provide the following information to a customer:

(1) a notice of proposed disconnection;

(2) a statement explaining the customer's rights and responsibilities;

(3) a list of local energy assistance providers;

(4) forms on which to declare inability to pay; and

(5) a statement explaining available time payment plans and other opportunities to secure continued utility service.

Subd. 3.Restrictions if disconnection necessary.

(a) If a residential customer must be involuntarily disconnected between October 15 and April 15 for failure to comply with subdivision 1, the disconnection must not occur:

(1) on a Friday, unless the customer declines to enter into a payment agreement offered that day in person or via personal contact by telephone by a municipal utility or cooperative electric association;

(2) on a weekend, holiday, or the day before a holiday;

(3) when utility offices are closed; or

(4) after the close of business on a day when disconnection is permitted, unless a field representative of a municipal utility or cooperative electric association who is authorized to enter into a payment agreement, accept payment, and continue service, offers a payment agreement to the customer.

Further, the disconnection must not occur until at least 20 days after the notice required in subdivision 2 has been mailed to the customer or 15 days after the notice has been personally delivered to the customer.

(b) If a customer does not respond to a disconnection notice, the customer must not be disconnected until the utility investigates whether the residential unit is actually occupied. If the unit is found to be occupied, the utility must immediately inform the occupant of the provisions of this section. If the unit is unoccupied, the utility must give seven days' written notice of the proposed disconnection to the local energy assistance provider before making a disconnection.

(c) If, prior to disconnection, a customer appeals a notice of involuntary disconnection, as provided by the utility's established appeal procedure, the utility must not disconnect until the appeal is resolved.

Subd. 4.Application to service limiters.

For the purposes of this section, "disconnection" includes a service or load limiter or any device that limits or interrupts electric service in any way.

216B.0975 DISCONNECTION DURING EXTREME HEAT CONDITIONS.

A utility may not effect an involuntary disconnection of residential services in affected counties when an excessive heat watch, heat advisory, or excessive heat warning issued by the National Weather Service is in effect. For purposes of this section, "utility" means a public utility providing electric service, municipal utility, or cooperative electric association.

216B.0976 NOTICE TO CITIES OF UTILITY DISCONNECTION.

Subdivision 1.Notice required.

Notwithstanding section 13.685 or any other law or administrative rule to the contrary, a public utility, cooperative electric association, or municipal utility must provide notice to a statutory city or home rule charter city, as prescribed by this section, of disconnection of a customer's gas or electric service. Upon written request from a city, on October 15 and November 1 of each year, or the next business day if that date falls on a Saturday or Sunday, a report must be made available to the city of the address of properties currently disconnected and the date of the disconnection. Upon written request from a city, between October 15 and April 15, daily reports must be made available of the address and date of any newly disconnected properties.

A city provided notice under this section must provide the information on disconnection to the police and fire departments of the city within three business days of receipt of the notice.

For the purpose of this section, "disconnection" means a cessation of services initiated by the public utility, cooperative electric association, or municipal utility that affects the primary heat source of a residence and service is not reconnected within 24 hours.

Subd. 2.Data.

Data on customers that are provided to cities under subdivision 1 are private data on individuals or nonpublic data, as defined in section 13.02.

History:

2008 c 253 s 2

216B.098 RESIDENTIAL CUSTOMER PROTECTIONS.

Subdivision 1.Applicability.

The provisions of this section apply to residential customers of public utilities, municipal utilities, and cooperative electric associations. Each municipal utility and cooperative electric association may establish terms and conditions for the plans and agreements required under subdivisions 2 and 3.

Subd. 2.Budget billing plans.

A utility shall offer a customer a budget billing plan for payment of charges for service, including adequate notice to customers prior to changing budget payment amounts. Municipal utilities having 3,000 or fewer customers are exempt from this requirement. Municipal utilities having more than 3,000 customers shall implement this requirement before July 1, 2003.

Subd. 3.Payment agreements.

A utility shall offer a payment agreement for the payment of arrears. Payment agreements must consider a customer's financial circumstances and any extenuating circumstances of the household. No additional service deposit may be charged as a consideration to continue service to a customer who has entered and is reasonably on time under an accepted payment agreement.

Subd. 4.Undercharges.

(a) A utility shall offer a payment agreement to customers who have been undercharged if no culpable conduct by the customer or resident of the customer's household caused the undercharge. The agreement must cover a period equal to the time over which the undercharge occurred or a different time period that is mutually agreeable to the customer and the utility, except that the duration of a payment agreement offered by a utility to a customer whose household income is at or below 50 percent of state median household income must consider the financial circumstances of the customer's household.

(b) No interest or delinquency fee may be charged as part of an undercharge agreement under this subdivision.

(c) If a customer inquiry or complaint results in the utility's discovery of the undercharge, the utility may bill for undercharges incurred after the date of the inquiry or complaint only if the utility began investigating the inquiry or complaint within a reasonable time after when it was made.

Subd. 5.Medically necessary equipment.

A utility shall reconnect or continue service to a customer's residence where a medical emergency exists or where medical equipment requiring electricity necessary to sustain life is in use, provided that the utility receives from a medical doctor written certification, or initial certification by telephone and written certification within five business days, that failure to reconnect or continue service will impair or threaten the health or safety of a resident of the customer's household. The customer must enter into a payment agreement.

Subd. 6.Commission authority.

In addition to any other authority, the commission has the authority to resolve customer complaints against a public utility, as defined in section 216B.02, subdivision 4, whether or not the complaint involves a violation of this chapter. The commission may delegate this authority to commission staff as it deems appropriate.


ACCOUNTING, MERCURY COSTS, DEPRECIATION

216B.10 ACCOUNTING.

Subdivision 1.System of accounts.

The commission shall establish a system of accounts to be kept by public utilities subject to its jurisdiction. A public utility which maintains its accounts in accordance with the system of accounts prescribed by a federal agency or authority shall be deemed to be in compliance with the system of accounts prescribed by the commission. Where optional accounting is prescribed by a federal agency or authority, the commission may prescribe which option is to be followed.

Subd. 2.Other business of public utility.

Every public utility engaged directly or indirectly in any other business than that of the production, transmission or furnishing of natural gas or electric service shall, if required by the commission, keep and render separately to the commission in like manner and form the accounts of all the other business, in which case all the provisions of Laws 1974, chapter 429 shall apply to the books, accounts, papers, and records of the other business.

Subd. 3.Manner and form.

Every public utility is required to keep and render its books, accounts, papers, and records accurately and faithfully in the manner and form prescribed by the commission, and to comply with all directions of the commission relating to these books, accounts, papers, and records.

Subd. 4.Reports.

The commission may require any public utility to file annual reports in the form and content, having regard for the provisions of this section, as the commission may require, and special reports concerning any matter about which the commission is authorized to inquire or to keep itself informed. The commission may require the reports to be verified. The basic financial statements in the annual report of a public utility may, at the direction of the public utilities commission, be examined by an independent certified public accountant and the accountant's opinion thereof included in the annual report filed with the commission.

Subd. 5.Audit.

The commission may require the examination and audit of all accounts, and all items shall be allocated to the accounts in the manner prescribed by the commission.

Subd. 6.

[Repealed, 1981 c 142 s 3]

History:

1974 c 429 s 10; 1980 c 614 s 123; 1986 c 444

216B.105 CUSTOMER SHARE OF MERCURY CONTROL COSTS.

A utility selling electricity at retail shall report in a biannual bill insert the amount of the customer's total bill that represents the utility's capital and operating costs to control mercury emissions to the atmosphere as required under sections 216B.68 to 216B.688.

History:

2006 c 201 s 3

216B.11 DEPRECIATION RATES AND PRACTICES.

The commission shall fix proper and adequate rates and methods of depreciation, amortization, or depletion in respect of utility property, and every public utility shall conform its depreciation, amortization or depletion accounts to the rates and methods fixed by the commission.


INVESTIGATORY REQUIREMENTS

216B.12 RIGHT OF ENTRANCE; INSPECTION.

Subdivision 1.Authority of commission and department.

The commissioners and the duly authorized officers and employees of the department, during business hours, may enter upon any premises occupied by any public utility for the purpose of making examinations and tests and to inspect the accounts, books, papers, and documents of any public utility for the purpose of exercising any power provided for in Laws 1974, chapter 429, and may set up and use on the premises any apparatus and appliance necessary therefor. Such public utility shall have the right to be represented at the making of the examinations, tests, and inspections. The public utility, its officers and employees, shall facilitate the examinations, tests, and inspections by giving every reasonable aid to the commissioners and any person or persons designated by the department for the duties aforesaid.

Subd. 2.

[Repealed, 1981 c 142 s 3]

History:

1974 c 429 s 12

216B.13 PRODUCTION AND EXAMINATION OF RECORDS.

Subdivision 1.Authority of commission.

The commission may require, by order served on any public utility in the manner provided herein for the service of orders, the production within this state at a reasonable time and place as the commission may designate, of any books, accounts, papers, or records of the public utility relating to its business or affairs within the state, pertinent to any lawful inquiry and kept by said public utility in any office or place within or without this state, or, at its option, verified or photostatic copies in lieu thereof, so that an examination thereof may be made by the commission or under its direction.

Subd. 2.

[Repealed, 1981 c 142 s 3]

History:

1974 c 429 s 13

216B.14 INVESTIGATION.

The commission upon complaint or upon its own initiative and whenever it may deem it necessary in the performance of its duties may investigate and examine the condition and operation of any public utility or any part thereof. In conducting the investigations the commission may proceed either with or without a hearing as it may deem best, but it shall make no order without affording the affected parties a hearing.

History:

1974 c 429 s 14


RATE HEARINGS

216B.15 HEARINGS; EXAMINER.

The commission may, in addition to the hearings specifically provided for by Laws 1974, chapter 429, conduct any other hearings as may reasonably be required in the administration of the powers and duties conferred upon it by Laws 1974, chapter 429. The commission may designate one of its members to act as an examiner for the purpose of holding any hearing which the commission has the power or authority to hold or in the event parties to the hearing so stipulate the commission may designate a qualified commission employee as the examiner. Reasonable notice of all hearings shall be given the persons interested therein as determined by the commission.

History:

1974 c 429 s 15

216B.16 RATE CHANGE; PROCEDURE; HEARING.

Subdivision 1.Notice.

Unless the commission otherwise orders, no public utility shall change a rate which has been duly established under this chapter, except upon 60 days' notice to the commission. The notice shall include statements of facts, expert opinions, substantiating documents, and exhibits, supporting the change requested, and state the change proposed to be made in the rates then in force and the time when the modified rates will go into effect. If the filing utility does not have an approved energy conservation improvement plan on file with the department, it shall also include in its notice an energy conservation plan pursuant to section 216B.241. A filing utility subject to rate regulation under section 216B.026 shall reference in its notice the energy conservation improvement plans of the generation and transmission cooperative providing energy conservation improvement programs to members of the filing utility pursuant to section 216B.241. The filing utility shall give written notice, as approved by the commission, of the proposed change to the governing body of each municipality and county in the area affected. All proposed changes shall be shown by filing new schedules or shall be plainly indicated upon schedules on file and in force at the time.

Subd. 1a.Settlement.

(a) When a public utility submits a general rate filing, the Office of Administrative Hearings, before conducting a contested case hearing, shall convene a settlement conference including all of the parties for the purpose of encouraging settlement of any or all of the issues in the contested case. If a stipulated settlement is not reached before the contested case hearing, the Office of Administrative Hearings may reconvene the settlement conference during or after completion of the contested case hearing at its discretion or a party's request. The Office of Administrative Hearings or the commission may, upon the request of any party and the public utility, extend the procedural schedule of the contested case in order to permit the parties to engage in settlement discussions. An extension must be for a definite period of time not to exceed 60 days.

(b) If the applicant and all intervening parties agree to a stipulated settlement of the case or parts of the case, the settlement must be submitted to the commission. The commission shall accept or reject the settlement in its entirety and, at any time until its final order is issued in the case, may require the Office of Administrative Hearings to conduct a contested case hearing. The commission may accept the settlement on finding that to do so is in the public interest and is supported by substantial evidence. If the commission does not accept the settlement, it may issue an order modifying the settlement subject to the approval of the parties. Each party shall have ten days in which to reject the proposed modification. If no party rejects the proposed modification, the commission's order becomes final. If the commission rejects the settlement, or a party rejects the commission's proposed modification, a contested case hearing must be completed.

Subd. 2.Suspension of proposed rate; hearing; final determination defined.

(a) Whenever there is filed with the commission a schedule modifying or resulting in a change in any rates then in force as provided in subdivision 1, the commission may suspend the operation of the schedule by filing with the schedule of rates and delivering to the affected utility a statement in writing of its reasons for the suspension at any time before the rates become effective. The suspension shall not be for a longer period than ten months beyond the initial filing date except as provided in this subdivision or subdivision 1a.

(b) During the suspension the commission shall determine whether all questions of the reasonableness of the rates requested raised by persons deemed interested or by the department can be resolved to the satisfaction of the commission. If the commission finds that all significant issues raised have not been resolved to its satisfaction, or upon petition by ten percent of the affected customers or 250 affected customers, whichever is less, it shall refer the matter to the Office of Administrative Hearings with instructions for a public hearing as a contested case pursuant to chapter 14, except as otherwise provided in this section.

(c) The commission may order that the issues presented by the proposed rate changes be bifurcated into two separate hearings as follows: (1) determination of the utility's revenue requirements and (2) determination of the rate design. Upon issuance of both administrative law judge reports, the issues shall again be joined for consideration and final determination by the commission.

(d) All prehearing discovery activities of state agency intervenors shall be consolidated and conducted by the Department of Commerce.

(e) If the commission does not make a final determination concerning a schedule of rates within ten months after the initial filing date, the schedule shall be deemed to have been approved by the commission; except if:

(1) an extension of the procedural schedule has been granted under paragraph (f) or subdivision 1a, in which case the schedule of rates is deemed to have been approved by the commission on the last day of the extended period of suspension; or

(2) a settlement has been submitted to and rejected by the commission and the commission does not make a final determination concerning the schedule of rates, the schedule of rates is deemed to have been approved 60 days after the initial or, if applicable, the extended period of suspension.

(f) If the commission finds that it has insufficient time during the suspension period to make a final determination of a case involving changes in general rates because of the need to make a final determination of any pending case involving changes in general rates under this section or section 237.075, the commission may extend the suspension period to allow up to a total of 90 additional calendar days to make the final determination. An extension of the suspension period under this paragraph does not alter the setting of interim rates under subdivision 3.

(g) For the purposes of this section, "final determination" means the initial decision of the commission and not any order which may be entered by the commission in response to a petition for rehearing or other further relief. The commission may further suspend rates until it determines all those petitions.

Subd. 3.Interim rate.

(a) Notwithstanding any order of suspension of a proposed increase in rates, the commission shall order an interim rate schedule into effect not later than 60 days after the initial filing date. The commission shall order the interim rate schedule ex parte without a public hearing. Notwithstanding the provisions of sections 216.25, 216B.27, and 216B.52, no interim rate schedule ordered by the commission pursuant to this subdivision shall be subject to an application for a rehearing or an appeal to a court until the commission has rendered its final determination.

(b) Unless the commission finds that exigent circumstances exist, the interim rate schedule shall be calculated using the proposed test year cost of capital, rate base, and expenses, except that it shall include: (1) a rate of return on common equity for the utility equal to that authorized by the commission in the utility's most recent rate proceeding; (2) rate base or expense items the same in nature and kind as those allowed by a currently effective order of the commission in the utility's most recent rate proceeding; and (3) no change in the existing rate design. In the case of a utility which has not been subject to a prior commission determination, the commission shall base the interim rate schedule on its most recent determination concerning a similar utility.

(c) If, at the time of its final determination, the commission finds that the interim rates are in excess of the rates in the final determination, the commission shall order the utility to refund the excess amount collected under the interim rate schedule, including interest on it which shall be at the rate of interest determined by the commission. The utility shall commence distribution of the refund to its customers within 120 days of the final order, not subject to rehearing or appeal. If, at the time of its final determination, the commission finds that the interim rates are less than the rates in the final determination, the commission shall prescribe a method by which the utility will recover the difference in revenues between the date of the final determination and the date the new rate schedules are put into effect. In addition, when an extension is granted for settlement discussions under subdivision 1a, the commission shall allow the utility to also recover the difference in revenues for a length of time equal to the length of the extension.

(d) If the public utility fails to make refunds within the period of time prescribed by the commission, the commission shall sue therefor and may recover on behalf of all persons entitled to a refund. In addition to the amount of the refund and interest due, the commission shall be entitled to recover reasonable attorney's fees, court costs and estimated cost of administering the distribution of the refund to persons entitled to it. No suit under this subdivision shall be maintained unless instituted within two years after the end of the period of time prescribed by the commission for repayment of refunds.

(e) The commission shall not order an interim rate schedule in a general rate case into effect as provided by this subdivision until at least four months after it has made a final determination concerning any previously filed change of the rate schedule or the change has otherwise become effective under subdivision 2, unless:

(1) the commission finds that a four-month delay would unreasonably burden the utility, its customers, or its shareholders and that an earlier imposition of interim rates is therefore necessary; or

(2) the utility files a second general rate case at least 12 months after it has filed a previous general rate case for which the commission has extended the suspension period under subdivision 2.

Subd. 4.Burden of proof.

The burden of proof to show that the rate change is just and reasonable shall be upon the public utility seeking the change.

Subd. 5.Determination after finding rate unacceptable.

If, after the hearing, the commission finds the rates to be unjust or unreasonable or discriminatory, the commission shall determine the rates to be charged or applied by the utility for the service in question and shall fix them by order to be served upon the utility. The rates shall thereafter be observed until changed, as provided by this chapter. In no event shall the rates exceed the level of rates requested by the public utility, except that individual rates may be adjusted upward or downward. Rate design changes shall be prospective from the effective date of the new rate schedules approved by the commission.

Subd. 6.Factors considered, generally.

The commission, in the exercise of its powers under this chapter to determine just and reasonable rates for public utilities, shall give due consideration to the public need for adequate, efficient, and reasonable service and to the need of the public utility for revenue sufficient to enable it to meet the cost of furnishing the service, including adequate provision for depreciation of its utility property used and useful in rendering service to the public, and to earn a fair and reasonable return upon the investment in such property. In determining the rate base upon which the utility is to be allowed to earn a fair rate of return, the commission shall give due consideration to evidence of the cost of the property when first devoted to public use, to prudent acquisition cost to the public utility less appropriate depreciation on each, to construction work in progress, to offsets in the nature of capital provided by sources other than the investors, and to other expenses of a capital nature. For purposes of determining rate base, the commission shall consider the original cost of utility property included in the base and shall make no allowance for its estimated current replacement value.

Subd. 6a.Construction work in progress.

To the extent that construction work in progress is included in the rate base, the commission shall determine in its discretion whether and to what extent the income used in determining the actual return on the public utility property shall include an allowance for funds used during construction, considering the following factors:

(1) the magnitude of the construction work in progress as a percentage of the net investment rate base;

(2) the impact on cash flow and the utility's capital costs;

(3) the effect on consumer rates;

(4) whether it confers a present benefit upon an identifiable class or classes of customers; and

(5) whether it is of a short-term nature or will be imminently useful in the provision of utility service.

Subd. 6b.Energy conservation improvement.

(a) Except as otherwise provided in this subdivision, all investments and expenses of a public utility as defined in section 216B.241, subdivision 1, paragraph (h), incurred in connection with energy conservation improvements shall be recognized and included by the commission in the determination of just and reasonable rates as if the investments and expenses were directly made or incurred by the utility in furnishing utility service.

(b) The commission shall not include investments and expenses for energy conservation improvements in determining (i) just and reasonable electric rates for retail electric service provided to large customer facilities whose electric utilities have been exempted by the commissioner under section 216B.241, subdivision 1a, paragraph (b), with respect to those large customer facilities; or (ii) just and reasonable gas rates for large energy facilities, large customer facilities whose natural gas utilities have been exempted by the commissioner under section 216B.241, subdivision 1a, paragraph (b), or commercial gas customer facilities whose natural gas utilities have been exempted by the commissioner under section 216B.241, subdivision 1a, paragraph (c).

(c) The commission may permit a public utility to file rate schedules providing for annual recovery of the costs of energy conservation improvements. These rate schedules may be applicable to less than all the customers in a class of retail customers if necessary to reflect the requirements of section 216B.241. The commission shall allow a public utility, without requiring a general rate filing under this section, to reduce the electric rates applicable to large customer facilities that have been exempted by the commissioner under section 216B.241, subdivision 1a, paragraph (b), and to reduce the gas rate applicable to a large energy facility, a large customer facility or commercial customer facility that has been exempted by the commissioner under section 216B.241, subdivision 1a, paragraph (b) or (c), or by the commission under section 216B.241, subdivision 2, by an amount that reflects the elimination of energy conservation improvement investments or expenditures for those facilities. In the event that the commission has set electric or gas rates based on the use of an accounting methodology that results in the cost of conservation improvements being recovered from utility customers over a period of years, the rate reduction may occur in a series of steps to coincide with the recovery of balances due to the utility for conservation improvements made by the utility on or before December 31, 2007.

(d) Investments and expenses of a public utility shall not include electric utility infrastructure costs as defined in section 216B.1636, subdivision 1, paragraph (b).

Subd. 6c.Incentive plan for energy conservation improvement.

(a) The commission may order public utilities to develop and submit for commission approval incentive plans that describe the method of recovery and accounting for utility conservation expenditures and savings. In developing the incentive plans the commission shall ensure the effective involvement of interested parties.

(b) In approving incentive plans, the commission shall consider:

(1) whether the plan is likely to increase utility investment in cost-effective energy conservation;

(2) whether the plan is compatible with the interest of utility ratepayers and other interested parties;

(3) whether the plan links the incentive to the utility's performance in achieving cost-effective conservation; and

(4) whether the plan is in conflict with other provisions of this chapter.

(c) The commission may set rates to encourage the vigorous and effective implementation of utility conservation programs. The commission may:

(1) increase or decrease any otherwise allowed rate of return on net investment based upon the utility's skill, efforts, and success in conserving energy;

(2) share between ratepayers and utilities the net savings resulting from energy conservation programs to the extent justified by the utility's skill, efforts, and success in conserving energy; and

(3) adopt any mechanism that satisfies the criteria of this subdivision, such that implementation of cost-effective conservation is a preferred resource choice for the public utility considering the impact of conservation on earnings of the public utility.

Subd. 6d.Wind energy; property tax.

An owner of a wind energy conversion facility which is required to pay property taxes under section 272.02, subdivision 22, or production taxes under section 272.029, and any related or successor provisions, or a public utility regulated by the Public Utilities Commission which purchases the wind-generated electricity may petition the commission to include in any power purchase agreement between the owner of the facility and the public utility the amount of property taxes and production taxes paid by the owner of the facility. The Public Utilities Commission shall require the public utility to amend the power purchase agreement to include the property taxes and production taxes paid by the owner of the facility in the price paid by the utility for wind-generated electricity if the commission finds:

(1) the owner of the facility has paid the property taxes or production taxes required by this subdivision;

(2) the power purchase agreement between the public utility and the owner does not already require the utility to pay the amount of property taxes or production taxes the owner has paid under this subdivision or, in the case of a power purchase agreement entered into prior to 1997, the amount of property or production taxes paid by the owner in any year of the power purchase agreement exceeds the amount of such property or production taxes included in the price paid by the utility to the owner, as reflected in the owner's bid documents; and

(3) the commission has approved a rate schedule containing provisions for the automatic adjustment of charges for utility service in direct relation to the charges ordered by the commission under section 272.02, subdivision 22, or 272.029.

Subd. 7.Energy and emission control products cost adjustment.

Notwithstanding any other provision of this chapter, the commission may permit a public utility to file rate schedules containing provisions for the automatic adjustment of charges for public utility service in direct relation to changes in:

(1) federally regulated wholesale rates for energy delivered through interstate facilities;

(2) direct costs for natural gas delivered;

(3) costs for fuel used in generation of electricity or the manufacture of gas; or

(4) prudent costs incurred by a public utility for sorbents, reagents, or chemicals used to control emissions from an electric generation facility, provided that these costs are not recovered elsewhere in rates. The utility must track and report annually the volumes and costs of sorbents, reagents, or chemicals using separate accounts by generating plant.

Subd. 7a.Performance-based gas purchasing adjustment.

The commission may permit a public utility to file rate schedules providing for annual adjustments reflecting rewards or penalties provided for in performance-based gas purchasing plans approved by the commission under section 216B.167.

Subd. 7b.Transmission cost adjustment.

(a) Notwithstanding any other provision of this chapter, the commission may approve a tariff mechanism for the automatic annual adjustment of charges for the Minnesota jurisdictional costs net of associated revenues of:

(i) new transmission facilities that have been separately filed and reviewed and approved by the commission under section 216B.243 or are certified as a priority project or deemed to be a priority transmission project under section 216B.2425;

(ii) new transmission facilities approved by the regulatory commission of the state in which the new transmission facilities are to be constructed, to the extent approval is required by the laws of that state, and determined by the Midcontinent Independent System Operator to benefit the utility or integrated transmission system; and

(iii) charges incurred by a utility under a federally approved tariff that accrue from other transmission owners' regionally planned transmission projects that have been determined by the Midcontinent Independent System Operator to benefit the utility or integrated transmission system.

(b) Upon filing by a public utility or utilities providing transmission service, the commission may approve, reject, or modify, after notice and comment, a tariff that:

(1) allows the utility to recover on a timely basis the costs net of revenues of facilities approved under section 216B.243 or certified or deemed to be certified under section 216B.2425 or exempt from the requirements of section 216B.243;

(2) allows the utility to recover charges incurred under a federally approved tariff that accrue from other transmission owners' regionally planned transmission projects that have been determined by the Midcontinent Independent System Operator to benefit the utility or integrated transmission system. These charges must be reduced or offset by revenues received by the utility and by amounts the utility charges to other regional transmission owners, to the extent those revenues and charges have not been otherwise offset;

(3) allows the utility to recover on a timely basis the costs net of revenues of facilities approved by the regulatory commission of the state in which the new transmission facilities are to be constructed and determined by the Midcontinent Independent System Operator to benefit the utility or integrated transmission system;

(4) allows a return on investment at the level approved in the utility's last general rate case, unless a different return is found to be consistent with the public interest;

(5) provides a current return on construction work in progress, provided that recovery from Minnesota retail customers for the allowance for funds used during construction is not sought through any other mechanism;

(6) allows for recovery of other expenses if shown to promote a least-cost project option or is otherwise in the public interest;

(7) allocates project costs appropriately between wholesale and retail customers;

(8) provides a mechanism for recovery above cost, if necessary to improve the overall economics of the project or projects or is otherwise in the public interest; and

(9) terminates recovery once costs have been fully recovered or have otherwise been reflected in the utility's general rates.

(c) A public utility may file annual rate adjustments to be applied to customer bills paid under the tariff approved in paragraph (b). In its filing, the public utility shall provide:

(1) a description of and context for the facilities included for recovery;

(2) a schedule for implementation of applicable projects;

(3) the utility's costs for these projects;

(4) a description of the utility's efforts to ensure the lowest costs to ratepayers for the project; and

(5) calculations to establish that the rate adjustment is consistent with the terms of the tariff established in paragraph (b).

(d) Upon receiving a filing for a rate adjustment pursuant to the tariff established in paragraph (b), the commission shall approve the annual rate adjustments provided that, after notice and comment, the costs included for recovery through the tariff were or are expected to be prudently incurred and achieve transmission system improvements at the lowest feasible and prudent cost to ratepayers.

Subd. 7c.Transmission assets transfer.

(a) Public utility owners of transmission facilities may, subject to Public Utilities Commission approval, transfer operational control or ownership of those transmission assets to a transmission company subject to Federal Energy Regulatory Commission jurisdiction. For transmission asset transfers by a public utility, the Public Utilities Commission must review the request to transfer either in the context of a general rate case under this section or by initiating other proceedings it determines provide adequate review of the transmission asset transfer. The Public Utilities Commission may limit, in whole or in part, the transfer of transmission assets or the timing of those transfers by a public utility if it finds the limitation in the public interest. The commission may only approve a transfer if it finds that the transfer is consistent with the public interest. In assessing the public interest, the commission shall evaluate, among other things, whether the transfer:

(1) facilitates the development of transmission infrastructure necessary to ensure reliability, encourages the development of renewable resources, and accommodates energy transfers within and between states;

(2) protects Minnesota ratepayers against the subsidization of wholesale transactions through retail rates;

(3) ensures, in the case of operational control of transmission assets, that the state retains jurisdiction over the transferring utility for all aspects of service under this chapter;

(4) impacts Minnesota retail rates; and

(5) protects Minnesota ratepayers from paying capital costs for transmission assets that have already been recovered.

(b) A transfer of operational control or ownership of transmission assets by a public utility under this subdivision is subject to section 216B.50. The relationship between a public utility transferring operational control of transmission assets to another entity under this subdivision is subject to the provisions of section 216B.48. If a public utility transfers ownership of its transmission assets to a transmission provider subject to the jurisdiction of the Federal Energy Regulatory Commission, the Public Utilities Commission may permit the utility to file a rate schedule providing for the automatic adjustment of charges to recover the cost of transmission services purchased under tariff rates approved by the Federal Energy Regulatory Commission.

(c) A municipal utility, a municipal power agency, or a joint venture pursuant to section 452.25 may transfer operational control or ownership of transmission assets to a transmission company, or make investments in a transmission company, if the governing body of the municipal utility, municipal power agency, or joint venture finds that the transfer or investment is consistent with the public interest and will facilitate the development of infrastructure necessary to ensure reliability.

Subd. 7d.Central Corridor utility zone cost adjustment.

(a) The Central Corridor utility zone is the area extending from the Union Depot Station in St. Paul to the proposed multimodal station in Minneapolis along the route of the light rail transit project connecting those two points, and an area extending approximately one-quarter mile from that route and including the entire University of Minnesota, Minneapolis campus.

(b) A public utility that provides retail electric service within the Central Corridor utility zone and that is required to replace, relocate, construct, or install new facilities, may apply to the commission for approval of new facilities in the Central Corridor utility zone and facilities outside the zone that the utility demonstrates must be changed as a direct result of changes within the zone. Facilities proposed under this subdivision may include transmission facilities, distribution facilities, generation facilities, advanced technology-assisted efficiency devices, and energy storage facilities not otherwise subject to section 216B.243, or chapter 216E, 216F, or 216G. Upon approval under paragraph (c), the utility may construct and install the facilities.

(c) The commission may approve the construction and installation of facilities in the Central Corridor mass transit utility zone proposed by a utility under paragraph (b) upon a finding:

(1) that the facilities:

(i) are necessary to provide electric service;

(ii) assist future development of renewable energy, conservation, electric vehicles, and advanced technology-assisted efficiency programs and devices; or

(iii) are exploratory, experimental, or research facilities to advance the use of renewable energy, conservation, electric vehicles, and advanced technology-assisted efficiency programs and devices;

(2) that the utility has engaged in a cooperative process with affected local and state government agencies in the design, planning, or construction of the Central Corridor utility zone project and changes to utility facilities;

(3) that the utility and local units of government have made reasonable efforts to seek federal, state, or private funds that may be available to mass transit and energy projects;

(4) that the utility has made reasonable efforts to minimize the project costs and maximize the value of the facilities to customers;

(5) that the utility has a plan to offer a comprehensive array of programs for residential, commercial, and industrial customers located within the mass transit zone;

(6) that the utility directs existing and planned solar energy programs to develop solar energy along the mass transit utility zone; and

(7) that the utility has made reasonable efforts to apply for federal funds to develop technology-assisted efficiency programs and devices within the mass transit utility zone.

(d) Upon request of the commission, the utility shall submit periodic reports to the commission reviewing the cost and benefits of the facilities constructed within the Central Corridor utility zone and their potential applicability to other areas outside the Central Corridor utility zone.

(e) Notwithstanding any other provision of this chapter, the commission may approve a tariff mechanism for automatic adjustment of charges for new, replaced, or relocated facilities installed under this subdivision in a manner consistent with this subdivision and the standards and procedures contained in subdivision 7b, except that no approval under section 216B.243 or certification under section 216B.2425 is required unless otherwise required by law. This section does not authorize a city-requested facilities surcharge.

(f) For the purpose of this subdivision, "technology-assisted efficiency programs and devices" includes, but is not limited to, infrastructure that integrates digital information and controls technology to improve the reliability, security, and efficiency of the electric grid.

Subd. 8.Advertising expense.

(a) The commission shall disapprove the portion of any rate which makes an allowance directly or indirectly for expenses incurred by a public utility to provide a public advertisement which:

(1) is designed to influence or has the effect of influencing public attitudes toward legislation or proposed legislation, or toward a rule, proposed rule, authorization or proposed authorization of the Public Utilities Commission or other agency of government responsible for regulating a public utility;

(2) is designed to justify or otherwise support or defend a rate, proposed rate, practice or proposed practice of a public utility;

(3) is designed primarily to promote consumption of the services of the utility;

(4) is designed primarily to promote good will for the public utility or improve the utility's public image; or

(5) is designed to promote the use of nuclear power or to promote a nuclear waste storage facility.

(b) The commission may approve a rate which makes an allowance for expenses incurred by a public utility to disseminate information which:

(1) is designed to encourage conservation of energy supplies;

(2) is designed to promote safety; or

(3) is designed to inform and educate customers as to financial services made available to them by the public utility.

(c) The commission shall not withhold approval of a rate because it makes an allowance for expenses incurred by the utility to disseminate information about corporate affairs to its owners.

Subd. 9.Charitable contribution.

The commission shall allow as operating expenses only those charitable contributions that the commission deems prudent and that qualify under section 300.66, subdivision 3. Only 50 percent of the qualified contributions are allowed as operating expenses.

Subd. 10.Intervenor compensation.

(a) A nonprofit organization or an individual granted formal intervenor status by the commission is eligible to receive compensation.

(b) The commission may order a utility to compensate all or part of an eligible intervenor's reasonable costs of participation in a general rate case that comes before the commission when the commission finds that the intervenor has materially assisted the commission's deliberation and when a lack of compensation would present financial hardship to the intervenor. Compensation may not exceed $50,000 for a single intervenor in any proceeding. For the purpose of this subdivision, "materially assisted" means that the intervenor's participation and presentation was useful and seriously considered, or otherwise substantially contributed to the commission's deliberations in the proceeding.

(c) In determining whether an intervenor has materially assisted the commission's deliberation, the commission must consider, among other factors, whether:

(1) the intervenor represented an interest that would not otherwise have been adequately represented;

(2) the evidence or arguments presented or the positions taken by the intervenor were an important factor in producing a fair decision;

(3) the intervenor's position promoted a public purpose or policy;

(4) the evidence presented, arguments made, issues raised, or positions taken by the intervenor would not have been a part of the record without the intervenor's participation; and

(5) the administrative law judge or the commission adopted, in whole or in part, a position advocated by the intervenor.

(d) In determining whether the absence of compensation would present financial hardship to the intervenor, the commission must consider:

(1) whether the costs presented in the intervenor's claim reflect reasonable fees for attorneys and expert witnesses and other reasonable costs; and

(2) the ratio between the costs of intervention and the intervenor's unrestricted funds.

(e) An intervenor seeking compensation must file a request and an affidavit of service with the commission, and serve a copy of the request on each party to the proceeding. The request must be filed 30 days after the later of (1) the expiration of the period within which a petition for rehearing, amendment, vacation, reconsideration, or reargument must be filed or (2) the date the commission issues an order following rehearing, amendment, vacation, reconsideration, or reargument.

(f) The compensation request must include:

(1) the name and address of the intervenor or representative of the nonprofit organization the intervenor is representing;

(2) proof of the organization's nonprofit, tax-exempt status;

(3) the name and docket number of the proceeding for which compensation is requested;

(4) a list of actual annual revenues and expenses of the organization the intervenor is representing for the preceding year and projected revenues, revenue sources, and expenses for the current year;

(5) the organization's balance sheet for the preceding year and a current monthly balance sheet;

(6) an itemization of intervenor costs and the total compensation request; and

(7) a narrative explaining why additional organizational funds cannot be devoted to the intervention.

(g) Within 30 days after service of the request for compensation, a party may file a response, together with an affidavit of service, with the commission. A copy of the response must be served on the intervenor and all other parties to the proceeding.

(h) Within 15 days after the response is filed, the intervenor may file a reply with the commission. A copy of the reply and an affidavit of service must be served on all other parties to the proceeding.

(i) If additional costs are incurred as a result of additional proceedings following the commission's initial order, the intervenor may file an amended request within 30 days after the commission issues an amended order. Paragraphs (e) to (h) apply to an amended request.

(j) The commission must issue a decision on intervenor compensation within 60 days of a filing by an intervenor.

(k) A party may request reconsideration of the commission's compensation decision within 30 days of the decision.

(l) If the commission issues an order requiring payment of intervenor compensation, the utility that was the subject of the proceeding must pay the compensation to the intervenor, and file with the commission proof of payment, within 30 days after the later of (1) the expiration of the period within which a petition for reconsideration of the commission's compensation decision must be filed or (2) the date the commission issues an order following reconsideration of its order on intervenor compensation.

Subd. 11.Pipeline safety programs.

All costs of a public utility that are necessary to comply with state pipeline safety programs under sections 216D.01 to 216D.07, 299F.56 to 299F.64, or 299J.01 to 299J.17 must be recognized and included by the commission in the determination of just and reasonable rates as if the costs were directly incurred by the utility in furnishing utility service.

Subd. 12.Exemption for small gas utility franchise.

(a) A municipality may file with the commission a resolution of its governing body requesting exemption from the provisions of this section for a public utility that is under a franchise with the municipality to supply natural, manufactured, or mixed gas and that serves 650 or fewer customers in the municipality as long as the public utility serves no more than a total of 2,000 customers.

(b) The commission shall grant an exemption from this section for that portion of a public utility's business that is requested by each municipality it serves. Furthermore, the commission shall also grant the public utility an exemption from this section for any service provided outside of a municipality's border that is considered by the commission to be incidental. The public utility shall file with the commission and the department all initial and subsequent changes in rates, tariffs, and contracts for service outside the municipality at least 30 days in advance of implementation.

(c) However, the commission shall require the utility to adopt the commission's policies and procedures governing disconnection during cold weather. The utility shall annually submit a copy of its municipally approved rates to the commission.

(d) In all cases covered by this subdivision in which an exemption for service outside of a municipality is granted, the commission may initiate an investigation under section 216B.17, on its own motion or upon complaint from a customer.

(e) If a municipality files with the commission a resolution of its governing body rescinding the request for exemption, the commission shall regulate the public utility's business in that municipality under this section.

Subd. 12a.Exemption for small electric utility franchise.

(a) An electric utility, operating as such in a bordering state and having fewer than 200 customers in Minnesota, is exempt from this section if the utility:

(1) charges Minnesota customers the same rates as those charged to customers in the bordering state;

(2) provides 60-day notice to the commission of rate increases for its Minnesota customers;

(3) provides individual, written notice of rate increases to its Minnesota customers;

(4) provides the commission with schedules of rates and tariffs charged in the bordering state and revenues by class under the former and proposed rates; and

(5) maintains an up-to-date tariff book with the department.

(b) The commission may initiate an investigation under section 216B.17, on its own motion or upon customer complaint with respect to the utility's rates and practices in Minnesota.

Subd. 13.Economic and community development.

The commission may allow a public utility to recover from ratepayers the expenses incurred for economic and community development.

Subd. 14.Low-income electric rate discount.

A public utility shall fund an affordability program for low-income customers in an amount based on a 50 percent electric rate discount on the first 400 kilowatt-hours consumed in a billing period for low-income residential customers of the utility. For the purposes of this subdivision, "low-income" describes a customer who is receiving assistance from the federal low-income home energy assistance program. The affordability program must be designed to target participating customers with the lowest incomes and highest energy costs in order to lower the percentage of income they devote to energy bills, increase their payments, and lower costs associated with collection activities on their accounts. For low-income customers who are 62 years of age or older or disabled, the program must, in addition to any other program benefits, include a 50 percent electric rate discount on the first 400 kilowatt-hours consumed in a billing period. For the purposes of this subdivision, "public utility" includes only those public utilities with more than 200,000 residential electric service customers. The commission may issue orders necessary to implement, administer, and recover the costs of the program on a timely basis.

Subd. 15.Low-income affordability programs.

(a) The commission must consider ability to pay as a factor in setting utility rates and may establish affordability programs for low-income residential ratepayers in order to ensure affordable, reliable, and continuous service to low-income utility customers. A public utility serving low-income residential ratepayers who use natural gas for heating must file an affordability program with the commission. For purposes of this subdivision, "low-income residential ratepayers" means ratepayers who receive energy assistance from the low-income home energy assistance program (LIHEAP).

(b) Any affordability program the commission orders a utility to implement must:

(1) lower the percentage of income that participating low-income households devote to energy bills;

(2) increase participating customer payments over time by increasing the frequency of payments;

(3) decrease or eliminate participating customer arrears;

(4) lower the utility costs associated with customer account collection activities; and

(5) coordinate the program with other available low-income bill payment assistance and conservation resources.

(c) In ordering affordability programs, the commission may require public utilities to file program evaluations that measure the effect of the affordability program on:

(1) the percentage of income that participating households devote to energy bills;

(2) service disconnections; and

(3) frequency of customer payments, utility collection costs, arrearages, and bad debt.

(d) The commission must issue orders necessary to implement, administer, and evaluate affordability programs, and to allow a utility to recover program costs, including administrative costs, on a timely basis. The commission may not allow a utility to recover administrative costs, excluding start-up costs, in excess of five percent of total program costs, or program evaluation costs in excess of two percent of total program costs. The commission must permit deferred accounting, with carrying costs, for recovery of program costs incurred during the period between general rate cases.

(e) Public utilities may use information collected or created for the purpose of administering energy assistance to administer affordability programs.

Subd. 16.Performance regulation plan tariffs.

A public utility providing natural gas services that has a performance regulation plan approved pursuant to section 216B.1675 shall file tariff provisions incorporating the provisions of that plan. Changes in the cost recovery of natural gas supplies must not be included within the plan.

Subd. 17.Travel, entertainment, and related employee expenses.

(a) The commission may not allow as operating expenses a public utility's travel, entertainment, and related employee expenses that the commission deems unreasonable and unnecessary for the provision of utility service. In order to assist the commission in evaluating the travel, entertainment, and related employee expenses that may be allowed for ratemaking purposes, a public utility filing a general rate case petition shall include a schedule separately itemizing all travel, entertainment, and related employee expenses as specified by the commission, including but not limited to the following categories:

(1) travel and lodging expenses;

(2) food and beverage expenses;

(3) recreational and entertainment expenses;

(4) board of director-related expenses, including and separately itemizing all compensation and expense reimbursements;

(5) expenses for the ten highest paid officers and employees, including and separately itemizing all compensation and expense reimbursements;

(6) dues and expenses for memberships in organizations or clubs;

(7) gift expenses;

(8) expenses related to owned, leased, or chartered aircraft; and

(9) lobbying expenses.

(b) To comply with the requirements of paragraph (a), each applicable expense incurred in the most recently completed fiscal year must be itemized separately, and each itemization must include the date of the expense, the amount of the expense, the vendor name, and the business purpose of the expense. The separate itemization required by this paragraph may be provided using standard accounting reports already utilized by the utility involved in the rate case, in a written format or an electronic format that is acceptable to the commission. For expenses identified in response to paragraph (a), clauses (1) and (2), the utility shall disclose the total amounts for each expense category and provide separate itemization for those expenses incurred by or on behalf of any employee at the level of vice president or higher and for board members. The petitioning utility shall also provide a one-page summary of the total amounts for each expense category included in the petitioning utility's proposed test year.

(c) Except as otherwise provided in this paragraph, data submitted to the commission under paragraph (a) are public data. The commission or an administrative law judge assigned to the case may treat the salary of one or more of the ten highest paid officers and employees, other than the five highest paid, as private data on individuals as defined in section 13.02, subdivision 12, or issue a protective order governing release of the salary, if the utility establishes that the competitive disadvantage to the utility that would result from release of the salary outweighs the public interest in access to the data. Access to the data by a government entity that is a party to the rate case must not be restricted.

Subd. 18.Election or ballot question expenses.

The commission may not allow a public utility to recover from ratepayers expenses resulting from a contribution or expenditure incurred to promote or defeat a candidate for public office or to advocate approval or defeat of a ballot question. This subdivision does not prohibit a public utility from engaging in political activity or making a contribution or expenditure otherwise permitted by law.

Subd. 19.Multiyear rate plan.

(a) A public utility may propose, and the commission may approve, approve as modified, or reject, a multiyear rate plan as provided in this subdivision. The term "multiyear rate plan" refers to a plan establishing the rates the utility may charge for each year of the specified period of years, which cannot exceed three years, to be covered by the plan. The commission may approve a multiyear rate plan only if it finds that the plan establishes just and reasonable rates for the utility, applying the factors described in subdivision 6. Consistent with subdivision 4, the burden of proof to demonstrate that the multiyear rate plan is just and reasonable is on the public utility proposing the plan.

(b) Rates charged under the multiyear rate plan must be based only upon the utility's reasonable and prudent costs of service over the term of the plan, as determined by the commission, provided that the costs are not being recovered elsewhere in rates. Rate adjustments authorized under subdivisions 6b and 7 may continue outside of a plan authorized under this subdivision.

(c) The commission may, by order, establish terms, conditions, and procedures for a multiyear rate plan necessary to implement this section and ensure that rates remain just and reasonable during the course of the plan, including terms and procedures for rate adjustment. At any time prior to conclusion of a multiyear rate plan, the commission, upon its own motion or upon petition of any party, has the discretion to examine the reasonableness of the utility's rates under the plan, and adjust rates as necessary.

(d) In reviewing a multiyear rate plan proposed in a general rate case under this section, the commission may extend the time requirements for issuance of a final determination prescribed in this section by an additional 90 days beyond its existing authority under subdivision 2, paragraph (f).

(e) A utility may not file a multiyear rate plan that would establish rates under the terms of the plan until after May 31, 2012.


SPECIAL RATES AND PRACTICES

216B.161 AREA DEVELOPMENT RATE PLAN.

Subdivision 1.Definitions.

(a) For purposes of this section, the following terms have the meanings given them in this subdivision.

(b) "Area development rate" means a rate schedule established by a utility that provides customers within an area development zone service under a base utility rate schedule, except that charges may be reduced from the base rate as agreed upon by the utility and the customer consistent with this section.

(c) "Area development zone" means a contiguous or noncontiguous area designated by an authority or municipality for development or redevelopment and within which one of the following conditions exists:

(1) obsolete buildings not suitable for improvement or conversion or other identified hazards to the health, safety, and general well-being of the community;

(2) buildings in need of substantial rehabilitation or in substandard condition; or

(3) low values and damaged investments.

(d) "Authority" means a rural development financing authority established under sections 469.142 to 469.151; a housing and redevelopment authority established under sections 469.001 to 469.047; a port authority established under sections 469.048 to 469.068; an economic development authority established under sections 469.090 to 469.108; a redevelopment agency as defined in sections 469.152 to 469.165; the Iron Range Resources and Rehabilitation Board established under section 298.22; a municipality that is administering a development district created under sections 469.124 to 469.133 or any special law; a municipality that undertakes a project under sections 469.152 to 469.165, except a town located outside the metropolitan area as defined in section 473.121, subdivision 2, or with a population of 5,000 persons or less; or a municipality that exercises the powers of a port authority under any general or special law.

(e) "Municipality" means a city, however organized, and, with respect to a project undertaken under sections 469.152 to 469.165, "municipality" has the meaning given in sections 469.152 to 469.165, and, with respect to a project undertaken under sections 469.142 to 469.151 or a county or multicounty project undertaken under sections 469.004 to 469.008, also includes any county.

Subd. 2.Area development rate.

The commission may allow gas or electric public utilities to offer area development rates. The program must be designed to assist industrial revitalization projects located within the service area of the participating utility.

Subd. 3.Terms and conditions of rate.

An area development rate offered under this section must:

(1) be offered for a specified length of time to be determined by the commission;

(2) be offered as a supplement to other development incentives offered by the authority or municipality in which the rate is available;

(3) be available only to new or expanding manufacturing or wholesale trade customers;

(4) be designed to recover at least the incremental cost of providing service to the participating customers;

(5) be offered in a fixed number of area development zones; and

(6) include a provision that the utility provide participating customers with an energy audit and inform those customers of all existing energy conservation programs available from the utility.

Recovery of costs under clause (4) must not be from residential customers. A utility within a general rate case, may seek recovery of the difference in revenue collected under the area development plan rate and what would have been collected under the standard tariff.

Subd. 4.

[Repealed by amendment, 1995 c 9 s 1]

216B.1611 INTERCONNECTION OF ON-SITE DISTRIBUTED GENERATION.

Subdivision 1.Purpose.

The purpose of this section is to:

(1) establish the terms and conditions that govern the interconnection and parallel operation of on-site distributed generation;

(2) provide cost savings and reliability benefits to customers;

(3) establish technical requirements that will promote the safe and reliable parallel operation of on-site distributed generation resources;

(4) enhance both the reliability of electric service and economic efficiency in the production and consumption of electricity; and

(5) promote the use of distributed resources in order to provide electric system benefits during periods of capacity constraints.

Subd. 2.Distributed generation; generic proceeding.

(a) The commission shall initiate a proceeding within 30 days of July 1, 2001, to establish, by order, generic standards for utility tariffs for the interconnection and parallel operation of distributed generation fueled by natural gas or a renewable fuel, or another similarly clean fuel or combination of fuels of no more than ten megawatts of interconnected capacity. At a minimum, these tariff standards must:

(1) to the extent possible, be consistent with industry and other federal and state operational and safety standards;

(2) provide for the low-cost, safe, and standardized interconnection of facilities;

(3) take into account differing system requirements and hardware, as well as the overall demand load requirements of individual utilities;

(4) allow for reasonable terms and conditions, consistent with the cost and operating characteristics of the various technologies, so that a utility can reasonably be assured of the reliable, safe, and efficient operation of the interconnected equipment; and

(5) establish (i) a standard interconnection agreement that sets forth the contractual conditions under which a company and a customer agree that one or more facilities may be interconnected with the company's utility system, and (ii) a standard application for interconnection and parallel operation with the utility system.

(b) The commission may develop financial incentives based on a public utility's performance in encouraging residential and small business customers to participate in on-site generation.

Subd. 3.Distributed generation tariff.

Within 90 days of the issuance of an order under subdivision 2:

(1) each public utility providing electric service at retail shall file a distributed generation tariff consistent with that order, for commission approval or approval with modification; and

(2) each municipal utility and cooperative electric association shall adopt a distributed generation tariff that addresses the issues included in the commission's order.

Subd. 4.Reporting requirements.

(a) Each electric utility shall maintain records concerning applications received for interconnection and parallel operation of distributed generation. The records must include the date each application is received, documents generated in the course of processing each application, correspondence regarding each application, and the final disposition of each application.

(b) Every electric utility shall file with the commissioner a distributed generation interconnection report for the preceding calendar year that identifies each distributed generation facility interconnected with the utility's distribution system. The report must list the new distributed generation facilities interconnected with the system since the previous year's report, any distributed generation facilities no longer interconnected with the utility's system since the previous report, the capacity of each facility, and the feeder or other point on the company's utility system where the facility is connected. The annual report must also identify all applications for interconnection received during the previous one-year period, and the disposition of the applications.

216B.1612 COMMUNITY-BASED ENERGY DEVELOPMENT; TARIFF.

Subdivision 1.Tariff establishment.

A tariff shall be established to optimize local, regional, and state benefits from renewable energy development and to facilitate widespread development of community-based renewable energy projects throughout Minnesota.

Subd. 2.Definitions.

(a) The terms used in this section have the meanings given them in this subdivision.

(b) "C-BED tariff" or "tariff" means a community-based energy development tariff.

(c) "Qualifying beneficiary" means:

(1) a Minnesota resident individually or as a member of a Minnesota limited liability company organized under chapter 322B and formed for the purpose of developing a C-BED project;

(2) a Minnesota nonprofit organization organized under chapter 317A;

(3) a Minnesota cooperative association organized under chapter 308A or 308B, including a rural electric cooperative association or a generation and transmission cooperative on behalf of and at the request of a member distribution utility;

(4) a Minnesota political subdivision or local government including, but not limited to, a municipal electric utility, or a municipal power agency on behalf of and at the request of a member distribution utility; the office of the commissioner of Iron Range resources and rehabilitation; a county, statutory or home rule charter city, town, school district, or public or private higher education institution; or any other local or regional governmental organization such as a board, commission, or association;

(5) a tribal council; or

(6) a legal entity (i) formed for a purpose other than to participate in C-BED projects; (ii) whose principal place of business or principal executive office is located in Minnesota; and (iii) that provides labor, services, equipment, components, or debt financing to a C-BED project.

A public utility, as defined in section 216B.02, subdivision 4, is not a qualifying beneficiary.

(d) "Qualifying revenue" includes, but is not limited to:

(1) royalties, distributions, dividends, and other payments flowing directly or indirectly to individuals who are qualifying beneficiaries;

(2) reasonable fees for consulting, development, professional, construction, and operations and maintenance services paid to qualifying beneficiaries;

(3) interest and fees paid to financial institutions that are qualifying beneficiaries;

(4) the value-added portion of payments for goods manufactured in Minnesota; and

(5) production taxes.

(e) "Discount rate" means the ten-year United States Treasury Yield as quoted in the Wall Street Journal as of the date of application for determination under subdivision 10, plus five percent; except that the discount rate applicable to any qualifying revenues contingent upon an equity investor earning a specified internal rate of return is the ten-year United States Treasury Yield, plus eight percent.

(f) "Standard reliability criteria" means:

(1) can be safely integrated into and operated within the utility's grid without causing any adverse or unsafe consequences; and

(2) is consistent with the utility's resource needs as identified in its most recent resource plan submitted under section 216B.2422.

(g) "Renewable" refers to a technology listed in section 216B.1691, subdivision 1, paragraph (a).

(h) "Community-based energy development project" or "C-BED project" means a new renewable energy project that either as a stand-alone project or part of a partnership under subdivision 8:

(1) has no single qualifying beneficiary, including any parent company or subsidiary of the qualifying beneficiary, owning more than 15 percent of a C-BED wind energy project unless: (i) the C-BED wind energy project consists of only one or two turbines; or (ii) the qualifying beneficiary is a public entity listed under paragraph (c), clause (4);

(2) demonstrates that at least 51 percent of the net present value of the gross revenues from a power purchase agreement over the life of the project are qualifying revenues; and

(3) has a resolution of support adopted by the county board of each county in which the project is to be located, or in the case of a project located within the boundaries of a reservation, the tribal council for that reservation.

(i) "Value-added portion" means the difference between the total sales price and the total cost of components, materials, and services purchased from or provided outside of Minnesota.

Subd. 3.Tariff rate.

(a) The tariff described in subdivision 4 must provide for a rate that is higher in the first ten years of the power purchase agreement than in the last ten years.

(b) The commission shall consider mechanisms to encourage the aggregation of C-BED projects.

(c) The commission shall require that C-BED projects provide sufficient security to secure performance under the power purchase agreement, and shall prohibit transfer of a C-BED project during the initial term of a power purchase agreement if the transfer will result in the project no longer qualifying under subdivision 2, paragraph (h).

Subd. 4.Utilities to offer tariff.

By December 1, 2007, each public utility providing electric service at retail shall file for commission approval a community-based energy development tariff consistent with subdivision 3. Within 90 days of the first commission approval order under this subdivision, each municipal power agency and generation and transmission cooperative electric association shall adopt a community-based energy development tariff as consistent as possible with subdivision 3.

Subd. 5.Priority for C-BED projects.

(a) A utility subject to section 216B.1691 that needs to construct new generation, or purchase the output from new generation, as part of its plan to satisfy its good faith objective and standard under that section must take reasonable steps to determine if one or more C-BED projects are available that meet the utility's cost and reliability requirements, applying standard reliability criteria, to fulfill some or all of the identified need at minimal impact to customer rates.

Nothing in this section shall be construed to obligate a utility to enter into a power purchase agreement under a C-BED tariff developed under this section.

(b) Each utility shall include in its resource plan submitted under section 216B.2422 a description of its efforts to purchase energy from C-BED projects, including a list of the projects under contract and the amount of C-BED energy purchased.

(c) The commission shall consider the efforts and activities of a utility to purchase energy from C-BED projects when evaluating its good faith effort towards meeting the renewable energy objective under section 216B.1691.

(d) A municipal power agency or generation and transmission cooperative shall, when issuing a request for proposals for C-BED projects to satisfy its standard obligation under section 216B.1691, provide notice to its member distribution utilities that they may propose, in partnership with other qualifying beneficiaries, a C-BED project for the consideration of the municipal power agency or generation and transmission cooperative.

Subd. 6.Property owner participation.

To the extent feasible, a developer of a C-BED project must provide, in writing, an opportunity to invest in the C-BED project to each property owner on whose property a high-voltage transmission line is constructed that will transmit the energy generated by the C-BED project to market. This subdivision applies if the property is located and the owner resides in the county where the C-BED project is located.

Subd. 7.Other C-BED tariff issues.

(a) A community-based project developer and a utility shall negotiate the rate and power purchase agreement terms consistent with the tariff established under subdivision 4.

(b) At the discretion of the developer, a community-based project developer and a utility may negotiate a power purchase agreement with terms different from the tariff established under subdivision 4.

(c) A C-BED project may be jointly developed with a non-C-BED project. However, the terms of the C-BED tariff may only apply to the portion of the energy production of the total project that is directly proportional to the energy produced by the C-BED project. A project that is operating under a power purchase agreement under a C-BED tariff is not eligible for net energy billing under section 216B.164, subdivision 3, or for production incentives under section 216C.41.

(d) A public utility must receive commission approval of a power purchase agreement for a C-BED tariffed project. The commission shall provide the utility's ratepayers an opportunity to address the reasonableness of the proposed power purchase agreement. Unless a party objects to a contract within 30 days of submission of the contract to the commission the contract is deemed approved.

Subd. 8.Community energy partnerships.

A utility providing electric service to retail or wholesale customers in Minnesota and an independent power producer may, subject to the limits specified in this section, participate in a community-based energy project, including as an owner, equity partner, or provider of technical or financial assistance.

Subd. 9.Local government and political subdivision powers.

A Minnesota political subdivision or local government may plan, develop, purchase, acquire, construct, and own a C-BED project and may sell output from that project as provided for in this section. A Minnesota political subdivision or local government may not acquire property under this subdivision through eminent domain. A Minnesota political subdivision or local government may operate, maintain, improve, and expand the C-BED project subject to any restrictions in this section.

Subd. 10.C-BED eligibility determination.

(a) A developer of a C-BED project may seek a predetermination of C-BED eligibility from the commissioner of commerce at any time, and must obtain a determination of C-BED eligibility from the commissioner of commerce, based on the project's final financing terms, before construction may begin. In seeking a determination of eligibility under this subdivision, a developer of a C-BED project must submit to the commissioner of commerce detailed financial projections demonstrating that, based on a net present value analysis, and applying the discount rate to qualifying revenues and gross revenues from a power purchase agreement, the project meets the requirements of subdivision 2, paragraph (h), clause (2).

(b) A project is not required to obtain a determination of C-BED eligibility under paragraph (a) if it has received, prior to May 18, 2010, an opinion letter from the commissioner indicating that the project qualifies as a C-BED project under this section.

(c) The commissioner's determination of C-BED eligibility of a project that obtained its initial opinion letter regarding C-BED eligibility from the commissioner or written notification from the Midwest Independent Systems Operator (MISO) that the project retains a position in the interconnection queue before May 18, 2010, must be based on the laws applicable at the time the initial opinion letter of C-BED eligibility was issued or the Midwest Independent System Operator interconnection queue position was obtained. A project subject to this paragraph may elect to have the determination of eligibility governed by the law in effect at the time of the determination.

216B.1613 STANDARDIZED CONTRACT.

Within 60 days of May 20, 2009, each utility, as defined in section 216B.1691, subdivision 1, paragraph (b), shall file with the commission a standardized contract form for the purchase of electricity from projects with a nameplate capacity of five megawatts or less. The standardized contract form must be similar in all material respects to the standard contract form previously filed with the commission under section 216B.2423, subdivision 3, including any revisions to that contract on file with the commission as of May 20, 2009. After consultation with wind developers and producers, a utility governed by this section may modify the standardized contract currently on file under section 216B.2423 prior to submitting its standard contract form under this section if the modifications are reasonably necessary to account for circumstances that are unique to that particular utility. The commission shall not approve a contract that is not in compliance with this section.

History:

2009 c 110 s 10

216B.162 COMPETITIVE RATE FOR ELECTRIC UTILITY.

Subdivision 1.Definitions.

(a) The terms used in this section have the meanings given them in this subdivision.

(b) "Effective competition" means a market situation in which an electric utility serves a customer that:

(1) is located within the electric utility's assigned service area determined under section 216B.39; and

(2) has the ability to obtain its energy requirements from an energy supplier that is not regulated by the commission under section 216B.16.

(c) "Competitive rate schedule" means a rate schedule under which an electric utility may set or change the price for its service to an individual customer or group of customers subject to effective competition.

(d) "Competitive rate" means the actual rate offered by the utility, and approved by the commission, to a customer subject to effective competition.

(e) "Discretionary rate reduction" means a specific reduction to an existing rate, offered voluntarily by the utility to an individual customer or group of customers and approved by the commission in accordance with subdivisions 10 and 11.

Subd. 2.Competitive rate schedule permitted.

(a) Notwithstanding section 216B.03, 216B.05, 216B.06, 216B.07, or 216B.16, the commission shall approve a competitive rate schedule when:

(1) the provision of service to a customer or a class of customers is subject to effective competition; and

(2) the schedule applies only to customers requiring electric service with a connected load of at least 2,000 kilowatts.

(b) The commission may approve a competitive rate schedule that applies to customers subject to effective competition and requiring electric service with a connected load less than 2,000 kilowatts.

(c) The commission shall make a final determination in a proceeding begun under this section within 90 days of a miscellaneous rate filing by the electric utility.

Subd. 3.Establishing or changing competitive rate schedule.

The commission shall establish or change a competitive rate schedule through a miscellaneous or general rate filing by the utility.

Subd. 4.Rates and terms of competitive rate schedule.

When the commission authorizes a competitive rate schedule for a customer class, it shall set the terms and conditions of service for that schedule, which must include:

(1) that the minimum rate for the schedule recover at least the incremental cost of providing the service, including the cost of additional capacity that is to be added while the rate is in effect and any applicable on-peak or off-peak differential;

(2) that the maximum possible rate reduction under a competitive rate schedule does not exceed the difference between the electric utility's applicable standard tariff and the cost to the customer of the lowest cost competitive energy supply;

(3) that the electric utility, within a general rate case, be allowed to seek recovery of the difference between the standard tariff and the competitive rate times the usage level during the test year period;

(4) a determination that a rate within a competitive rate schedule meets the conditions of section 216B.03, for other customers in the same customer class;

(5) that the rate does not compete with district heating or cooling provided by a district heating utility as defined by section 216B.166, subdivision 2, paragraph (c); and

(6) that the rate may not be offered to a customer in which the utility has a financial interest greater than 50 percent.

Subd. 5.Competitive rate offered.

Within its own assigned service territory, the utility, at its discretion and using its best judgment at the time, may offer a competitive rate to a customer subject to effective competition.

Subd. 6.Interim competitive rate.

Notwithstanding section 216B.16, subdivision 3, a proposed competitive rate takes effect on an interim basis after filing the proposed rate with the commission and on the date established by the electric utility. While an interim competitive rate is in effect, the difference between rates under the competitive rate and rates under the standard tariff for that class are not subject to recovery or refund. If the commission does not approve the competitive rate, the electric utility may seek to recover the difference in revenues between the interim competitive rate and the standard tariff from the customer that was offered the competitive rate.

Subd. 7.Commission determination.

(a) Except as provided under subdivision 6, competitive rates offered by electric utilities under this section must be filed with the commission and must be approved, modified, or rejected by the commission within 90 days. The utility's filing must include statements of fact demonstrating that the proposed rates meet the standards of this subdivision. The filing must be served on the department and the Office of the Attorney General at the same time as it is served on the commission.

(b) In reviewing a specific rate proposal, the commission shall determine:

(1) that the rate meets the terms and conditions in subdivision 4, unless the commission determines that waiver of one or more terms and conditions would be in the public interest;

(2) that the consumer can obtain its energy requirements from an energy supplier not rate-regulated by the commission under section 216B.16;

(3) that the customer is not likely to take service from the electric utility seeking to offer the competitive rate if the customer was charged the electric utility's standard tariffed rate; and

(4) that after consideration of environmental and socioeconomic impacts it is in the best interest of all other customers to offer the competitive rate to the customer subject to effective competition.

(c) If the commission approves the competitive rate, it becomes effective as agreed to by the electric utility and the customer. If the competitive rate is modified by the commission, the commission shall issue an order modifying the competitive rate subject to the approval of the electric utility and the customer. Each party has ten days in which to reject the proposed modification. If no party rejects the proposed modification, the commissioner's order becomes final. If either party rejects the commission's proposed modification, the electric utility, on its behalf or on the behalf of the customer, may submit to the commission a modified version of the commission's proposal. The commission shall accept or reject the modified version within 30 days. If the commission rejects the competitive rate, it shall issue an order indicating the reasons for the rejection.

Subd. 8.Energy efficiency improvement; expense recovery.

If the commission approves a competitive rate or the parties agree to a modified rate, the commission may require the electric utility to provide the customer with an energy audit and assist in implementing cost-effective energy efficiency improvements to assure that the customer's use of electricity is efficient. An investment in cost-effective energy conservation improvements required under this section must be treated as an energy conservation improvement program and included in the department's determination of significant investments under section 216B.241. The utility shall recover energy conservation improvement expenses in a rate proceeding under section 216B.16 or 216B.17 in the same manner as the commission authorizes for the recovery of conservation expenditures made under section 216B.241.

Subd. 9.

[Repealed, 1995 c 6 s 2]

Subd. 10.Discretionary rate reduction permitted.

Notwithstanding sections 216B.03, 216B.06, 216B.07, and 216B.16, a public utility whose rates are regulated under this chapter may, at its discretion, offer a reduced rate for tariffed electric services to eligible customers. The commission may approve a discretionary rate reduction provided that:

(1) the reduction is offered to customers who are located within the exclusive service territory of the public utility that offers discretionary rate reductions or to potential customers who are not customers of a Minnesota electric utility, as defined in section 216B.38, but who propose to be located within the exclusive service territory of the public utility;

(2) the reduction applies to customers requiring electric service with a connected load of at least 2,000 kilowatts;

(3) the reduced rate recovers at least the incremental cost of providing the service, including the cost of additional capacity that is to be added while the rate is in effect and any applicable on-peak or off-peak differential;

(4) in the event the commission has approved unbundled rates, the reduction is not offered for any unbundled service other than generation, unless the unbundled service is available to the customer from a competitive supplier;

(5) the reduced rate does not compete with district heating or cooling services provided by a district heating utility as defined by section 216B.166, subdivision 2, paragraph (c); and

(6) the reduced rate does not compete with a natural gas service provided by a natural gas utility and regulated by the commission.

Subd. 11.Commission determination.

(a) Proposals for discretionary rate reductions offered by utilities must be filed with the commission, with copies of the filing served upon the department and the office of attorney general at the same time it is served upon the commission. The commission shall review the proposals according to procedures developed under section 216B.05, subdivision 2a. The commission shall not approve discretionary rate reductions offered by public utilities that do not have an accepted resource plan on file with the commission. The commission shall not approve discretionary rate reductions unless the utility has made the customer aware of all cost-effective opportunities for energy efficiency improvements offered by the utility.

(b) Public utilities that provide service under discretionary rate reductions shall not, through increased revenue requirements or through prospective rate design changes, recover any revenues forgone due to the discretionary rate reductions, nor shall the commission grant such recovery.

216B.1621 ELECTRIC SERVICE AGREEMENT.

Subdivision 1.Agreement.

When a retail customer of a public utility proposes to acquire power from or construct a new electric power generation facility in the assigned service area of the utility serving the retail customer to provide all or part of the customer's electric service needs, the public utility may negotiate with and enter into an agreement with the customer to supply electric power to the customer in order to defer construction of the facility until the utility has need of power generated by the proposed facility, if the Public Utilities Commission approves the agreement under subdivision 2.

Subd. 2.Commission approval.

(a) The commission shall approve an agreement under this section upon finding that:

(1) the proposed electric service power generation facility could reasonably be expected to qualify for a market value exclusion under section 272.0211;

(2) the public utility has a contractual option to purchase electric power from the proposed facility; and

(3) the public utility can use the output from the proposed facility to meet its future need for power as demonstrated in the most recent resource plan filed with and approved by the commission under section 216B.2422.

(b) Sections 216B.03, 216B.05, 216B.06, 216B.07, 216B.16, 216B.162, and 216B.23 do not apply to an agreement under this section.

History:

1996 c 444 s 1

216B.163 FLEXIBLE TARIFF.

Subdivision 1.Definitions.

(a) For the purposes of this section, the terms defined in this subdivision have the meanings given them.

(b) "Effective competition" means that a customer of a gas utility who either receives interruptible service or whose daily requirement exceeds 50,000 cubic feet maintains or plans on acquiring the capability to switch to the same, equivalent or substitutable energy supplies or service, except indigenous biomass energy supplies composed of wood products, grain, biowaste, and cellulosic materials, at comparable prices from a supplier not regulated by the commission.

(c) "Flexible tariff" means a rate schedule under which a gas utility may set or change the price for its service to an individual customer or group of customers without prior approval of the commission within a range of prices determined by the commission to be just and reasonable.

Subd. 2.Flexible tariff permitted.

Notwithstanding section 216B.03, 216B.05, 216B.06, 216B.07, or 216B.16, the commission may approve a flexible tariff for any class of customers of a gas utility when provision of service, including the sale or transportation of gas, to any customers within the class is subject to effective competition. Upon application of a gas utility, the commission shall find that effective competition exists for a class of customers taking interruptible service at a level exceeding 199,000 cubic feet per day. A gas utility may apply a flexible tariff only to a customer that is subject to effective competition and a gas utility may not apply a flexible tariff or otherwise reduce its rates to compete with indigenous biomass energy supplies. Customers of a gas utility whose only alternative source of energy is gas from a supplier not regulated by the commission and who must use the gas utility's system to transport the gas are not subject to effective competition unless the customers have or can reasonably acquire the capability to bypass the gas utility's system to obtain gas from a supplier not regulated by the commission. A customer subject to effective competition may elect to take service either under the flexible tariff or under the appropriate nonflexible tariff for that class of service set in accordance with section 216B.03, provided that a customer that uses an alternative energy supply or service from a supplier not regulated by the commission for reasons of price are deemed to have elected to take service under the flexible tariff.

Subd. 2a.

[Expired]

Subd. 3.Establishing or changing flexible tariff.

The commission may establish a flexible tariff through a miscellaneous rate filing only if the filing does not seek to recover revenues the utility expects to lose by implementing flexible tariffs from customers who do not take service under the flexible tariff, nor to change another rate. If a gas utility requests authority to establish a flexible tariff and as part of that request seeks to recover revenues the utility expects to lose by implementing flexible tariffs from customers who do not take service under the flexible tariff or to change other rates, the commission may only establish that flexible tariff within a general rate case for that gas utility.

Subd. 4.Rates and terms of service.

Whenever the commission authorizes a flexible tariff, it shall set the terms, and conditions of service for that tariff, including:

(1) the minimum rate for the tariff, which must recover at least the incremental cost of providing the service;

(2) the maximum rate for the tariff; and

(3) a requirement that a customer who elects to take service under the flexible tariff remain on that tariff for a reasonable period of time.

The commission may set the terms and conditions of service for a flexible tariff in a gas utility proceeding, a miscellaneous filing, or a complaint proceeding under section 216B.17.

Subd. 5.Recovery of revenues.

In a general rate case that establishes a flexible tariff for a gas utility, and in each general rate case of a gas utility for which a flexible tariff has been authorized, the commission shall determine a projected level of revenues and expenses from services under that tariff and use the projection to determine the utility's overall rates. That method used to establish a level of projected revenues may not limit the gas utility's ability or right to set rates for a customer taking service under the flexible tariff.

Subd. 6.Interim flexible tariff.

Notwithstanding section 216B.16, subdivision 3, if a gas utility files with the commission to establish or change a flexible tariff the commission shall permit the proposed flexible tariff to take effect on an interim basis no later than 30 days after filing. If any customers receive an increase in rates during the period that an interim flexible tariff is in effect, the increase is subject to refund as provided in section 216B.16, subdivision 3. The gas utility shall provide ten days' written notice, or other notice as may be established by contract not to exceed 30 days, to a customer before implementing an interim rate change for that customer under this section.

Subd. 7.Final determination.

The commission shall make a final determination in a proceeding begun under this section for approval of a flexible tariff, other than a filing made within a general rate case, within 180 days of the filing by the gas utility.

Subd. 8.

MS 2002 [Obsolete]

216B.1635 RECOVERY OF GAS UTILITY INFRASTRUCTURE COSTS.

Subdivision 1.Definitions.

(a) "Gas utility" means a public utility as defined in section 216B.02, subdivision 4, that furnishes natural gas service to retail customers.

(b) "Gas utility infrastructure costs" or "GUIC" means costs incurred in gas utility projects that:

(1) do not serve to increase revenues by directly connecting the infrastructure replacement to new customers;

(2) are in service but were not included in the gas utility's rate base in its most recent general rate case, or are planned to be in service during the period covered by the report submitted under subdivision 2, but in no case longer than the one-year forecast period in the report; and

(3) do not constitute a betterment, unless the betterment is based on requirements by a political subdivision or a federal or state agency, as evidenced by specific documentation, an order, or other similar requirement from the government entity requiring the replacement or modification of infrastructure.

(c) "Gas utility projects" means:

(1) replacement of natural gas facilities located in the public right-of-way required by the construction or improvement of a highway, road, street, public building, or other public work by or on behalf of the United States, the state of Minnesota, or a political subdivision; and

(2) replacement or modification of existing natural gas facilities, including surveys, assessments, reassessment, and other work necessary to determine the need for replacement or modification of existing infrastructure that is required by a federal or state agency.

Subd. 2.Gas infrastructure filing.

A public utility submitting a petition to recover gas infrastructure costs under this section must submit to the commission, the department, and interested parties a gas infrastructure project plan report and a petition for rate recovery of only incremental costs associated with projects under subdivision 1, paragraph (c). The report and petition must be made at least 150 days in advance of implementation of the rate schedule, provided that the rate schedule will not be implemented until the petition is approved by the commission pursuant to subdivision 5. The report must be for a forecast period of one year.

Subd. 3.Gas infrastructure project plan report.

The gas infrastructure project plan report required to be filed under subdivision 2 shall include all pertinent information and supporting data on each proposed project including, but not limited to, project description and scope, estimated project costs, and project in-service date.

Subd. 4.Cost recovery petition for utility's facilities.

Notwithstanding any other provision of this chapter, the commission may approve a rate schedule for the automatic annual adjustment of charges for gas utility infrastructure costs net of revenues under this section, including a rate of return, income taxes on the rate of return, incremental property taxes, incremental depreciation expense, and any incremental operation and maintenance costs. A gas utility's petition for approval of a rate schedule to recover gas utility infrastructure costs outside of a general rate case under section 216B.16 is subject to the following:

(1) a gas utility may submit a filing under this section no more than once per year; and

(2) a gas utility must file sufficient information to satisfy the commission regarding the proposed GUIC. The information includes, but is not limited to:

(i) the information required to be included in the gas infrastructure project plan report under subdivision 3;

(ii) the government entity ordering or requiring the gas utility project and the purpose for which the project is undertaken;

(iii) a description of the estimated costs and salvage value, if any, associated with the existing infrastructure replaced or modified as a result of the project;

(iv) a comparison of the utility's estimated costs included in the gas infrastructure project plan and the actual costs incurred, including a description of the utility's efforts to ensure the costs of the facilities are reasonable and prudently incurred;

(v) calculations to establish that the rate adjustment is consistent with the terms of the rate schedule, including the proposed rate design and an explanation of why the proposed rate design is in the public interest;

(vi) the magnitude and timing of any known future gas utility projects that the utility may seek to recover under this section;

(vii) the magnitude of GUIC in relation to the gas utility's base revenue as approved by the commission in the gas utility's most recent general rate case, exclusive of gas purchase costs and transportation charges;

(viii) the magnitude of GUIC in relation to the gas utility's capital expenditures since its most recent general rate case; and

(ix) the amount of time since the utility last filed a general rate case and the utility's reasons for seeking recovery outside of a general rate case.

Subd. 5.Commission action.

Upon receiving a gas utility report and petition for cost recovery under subdivision 2 and assessment and verification under subdivision 4, the commission may approve the annual GUIC rate adjustments provided that, after notice and comment, the costs included for recovery through the rate schedule are prudently incurred and achieve gas facility improvements at the lowest reasonable and prudent cost to ratepayers.

Subd. 6.Rate of return.

The return on investment for the rate adjustment shall be at the level approved by the commission in the public utility's last general rate case, unless the commission determines that a different rate of return is in the public interest.

Subd. 7.Commission authority; rules.

The commission may issue orders and adopt rules necessary to implement and administer this section.

NOTE: This section expires June 30, 2023. Laws 2005, chapter 97, article 10, section 3, as amended by Laws 2013, chapter 85, article 7, section 9.

216B.1636 RECOVERY OF ELECTRIC UTILITY INFRASTRUCTURE COSTS.

Subdivision 1.Definitions.

(a) "Electric utility" means a public utility as defined in section 216B.02, subdivision 4, that furnishes electric service to retail customers.

(b) "Electric utility infrastructure costs" or "EUIC" means costs for electric utility infrastructure projects that were not included in the electric utility's rate base in its most recent general rate case.

(c) "Electric utility infrastructure projects" means projects owned by an electric utility that:

(1) replace or modify existing electric utility infrastructure, including utility-owned buildings, if the replacement or modification is shown to conserve energy or use energy more efficiently, consistent with section 216B.241, subdivision 1c; or

(2) conserve energy or use energy more efficiently by using waste heat recovery converted into electricity as defined in section 216B.241, subdivision 1, paragraph (n).

Subd. 2.Filing.

(a) The commission may approve an electric utility's petition for a rate schedule to recover EUIC under this section. An electric utility may petition the commission to recover a rate of return, income taxes on the rate of return, incremental property taxes, if any, plus incremental depreciation expense associated with EUIC.

(b) The filing is subject to the following:

(1) an electric utility may submit a filing under this section no more than once per year; and

(2) an electric utility must file sufficient information to satisfy the commission regarding the proposed EUIC or be subject to denial by the commission. The information includes, but is not limited to:

(i) the location, description, and costs associated with the project;

(ii) evidence that the electric utility infrastructure project will conserve energy or use energy more efficiently than similar utility facilities currently used by the electric utility;

(iii) the proposed schedule for implementation;

(iv) a description of the costs, and salvage value, if any, associated with the existing infrastructure replaced or modified as a result of the project;

(v) the proposed rate design and an explanation of why the proposed rate design is in the public interest;

(vi) the magnitude and timing of any known future electric utility projects that the utility may seek to recover under this section;

(vii) the magnitude of EUIC in relation to the electric utility's base revenue as approved by the commission in the electric utility's most recent general rate case, exclusive of fuel cost adjustments;

(viii) the magnitude of EUIC in relation to the electric utility's capital expenditures since its most recent general rate case;

(ix) the amount of time since the utility last filed a general rate case and the utility's reasons for seeking recovery outside of a general rate case;

(x) documentation supporting the calculation of the EUIC; and

(xi) a cost and benefit analysis showing that the electric utility infrastructure project is in the public interest.

(c) Upon approval of the proposed projects and associated EUIC rate schedule, the utility may implement the electric utility infrastructure projects.

Subd. 3.Commission authority; orders.

The commission may issue orders necessary to implement and administer this section.

216B.1637 [Repealed, 2013 c 85 art 13 s 6]

216B.164 COGENERATION AND SMALL POWER PRODUCTION.

Subdivision 1.Scope and purpose.

This section shall at all times be construed in accordance with its intent to give the maximum possible encouragement to cogeneration and small power production consistent with protection of the ratepayers and the public.

Subd. 2.Applicability.

This section as well as any rules promulgated by the commission to implement this section or the Public Utility Regulatory Policies Act of 1978, Public Law 95-617, Statutes at Large, volume 92, page 3117, and the Federal Energy Regulatory Commission regulations thereunder, Code of Federal Regulations, title 18, part 292, shall, unless otherwise provided in this section, apply to all Minnesota electric utilities, including cooperative electric associations and municipal electric utilities.

Subd. 2a.Definitions.

(a) For the purposes of this section, the following terms have the meanings given them.

(b) "Aggregated meter" means a meter located on the premises of a customer's owned or leased property that is contiguous with property containing the customer's designated meter.

(c) "Capacity" means the number of megawatts alternating current (AC) at the point of interconnection between a distributed generation facility and a utility's electric system.

(d) "Cogeneration" means a combined process whereby electrical and useful thermal energy are produced simultaneously.

(e) "Contiguous property" means property owned or leased by the customer sharing a common border, without regard to interruptions in contiguity caused by easements, public thoroughfares, transportation rights-of-way, or utility rights-of-way.

(f) "Customer" means the person who is named on the utility electric bill for the premises.

(g) "Designated meter" means a meter that is physically attached to the customer's facility that the customer-generator designates as the first meter to which net metered credits are to be applied as the primary meter for billing purposes when the customer is serviced by more than one meter.

(h) "Distributed generation" means a facility that:

(1) has a capacity of ten megawatts or less;

(2) is interconnected with a utility's distribution system, over which the commission has jurisdiction; and

(3) generates electricity from natural gas, renewable fuel, or a similarly clean fuel, and may include waste heat, cogeneration, or fuel cell technology.

(i) "High-efficiency distributed generation" means a distributed energy facility that has a minimum efficiency of 40 percent, as calculated under section 272.0211, subdivision 1.

(j) "Net metered facility" means an electric generation facility constructed for the purpose of offsetting energy use through the use of renewable energy or high-efficiency distributed generation sources.

(k) "Renewable energy" has the meaning given in section 216B.2411, subdivision 2.

(l) "Standby charge" means a charge imposed by an electric utility upon a distributed generation facility for the recovery of costs for the provision of standby services, as provided for in a utility's tariffs approved by the commission, necessary to make electricity service available to the distributed generation facility.

Subd. 3.Purchases; small facilities.

(a) This paragraph applies to cooperative electric associations and municipal utilities. For a qualifying facility having less than 40-kilowatt capacity, the customer shall be billed for the net energy supplied by the utility according to the applicable rate schedule for sales to that class of customer. In the case of net input into the utility system by a qualifying facility having less than 40-kilowatt capacity, compensation to the customer shall be at a per kilowatt-hour rate determined under paragraph (c) or (d).

(b) This paragraph applies to public utilities. For a qualifying facility having less than 1,000-kilowatt capacity, the customer shall be billed for the net energy supplied by the utility according to the applicable rate schedule for sales to that class of customer. In the case of net input into the utility system by a qualifying facility having: (1) more than 40-kilowatt but less than 1,000-kilowatt capacity, compensation to the customer shall be at a per kilowatt-hour rate determined under paragraph (c); or (2) less than 40-kilowatt capacity, compensation to the customer shall be at a per-kilowatt rate determined under paragraph (d).

(c) In setting rates, the commission shall consider the fixed distribution costs to the utility not otherwise accounted for in the basic monthly charge and shall ensure that the costs charged to the qualifying facility are not discriminatory in relation to the costs charged to other customers of the utility. The commission shall set the rates for net input into the utility system based on avoided costs as defined in the Code of Federal Regulations, title 18, section 292.101, paragraph (b)(6), the factors listed in Code of Federal Regulations, title 18, section 292.304, and all other relevant factors.

(d) Notwithstanding any provision in this chapter to the contrary, a qualifying facility having less than 40-kilowatt capacity may elect that the compensation for net input by the qualifying facility into the utility system shall be at the average retail utility energy rate. "Average retail utility energy rate" is defined as the average of the retail energy rates, exclusive of special rates based on income, age, or energy conservation, according to the applicable rate schedule of the utility for sales to that class of customer.

(e) If the qualifying facility or net metered facility is interconnected with a nongenerating utility which has a sole source contract with a municipal power agency or a generation and transmission utility, the nongenerating utility may elect to treat its purchase of any net input under this subdivision as being made on behalf of its supplier and shall be reimbursed by its supplier for any additional costs incurred in making the purchase. Qualifying facilities or net metered facilities having less than 1,000-kilowatt capacity if interconnected to a public utility, or less than 40-kilowatt capacity if interconnected to a cooperative electric association or municipal utility may, at the customer's option, elect to be governed by the provisions of subdivision 4.

Subd. 3a.Net metered facility.

(a) Except for customers receiving a value of solar rate under subdivision 10, a customer with a net metered facility having a capacity of 40 kilowatts or greater but less than 1,000 kilowatts that is interconnected to a public utility may elect to be compensated for the customer's net input into the utility system in the form of a kilowatt-hour credit on the customer's energy bill carried forward and applied to subsequent energy bills. Any net input supplied by the customer into the utility system that exceeds energy supplied to the customer by the utility during a calendar year must be compensated at the applicable rate.

(b) A public utility may not impose a standby charge on a net metered or qualifying facility:

(1) of 100 kilowatts or less capacity; or

(2) of more than 100 kilowatts capacity, except in accordance with an order of the commission establishing the allowable costs to be recovered through standby charges.

Subd. 4.Purchases; wheeling; costs.

(a) Except as otherwise provided in paragraph (c), this subdivision shall apply to all qualifying facilities having 40-kilowatt capacity or more as well as qualifying facilities as defined in subdivision 3 and net metered facilities under subdivision 3a, if interconnected to a cooperative electric association or municipal utility, or 1,000-kilowatt capacity or more if interconnected to a public utility, which elect to be governed by its provisions.

(b) The utility to which the qualifying facility is interconnected shall purchase all energy and capacity made available by the qualifying facility. The qualifying facility shall be paid the utility's full avoided capacity and energy costs as negotiated by the parties, as set by the commission, or as determined through competitive bidding approved by the commission. The full avoided capacity and energy costs to be paid a qualifying facility that generates electric power by means of a renewable energy source are the utility's least cost renewable energy facility or the bid of a competing supplier of a least cost renewable energy facility, whichever is lower, unless the commission's resource plan order, under section 216B.2422, subdivision 2, provides that the use of a renewable resource to meet the identified capacity need is not in the public interest.

(c) For all qualifying facilities having 30-kilowatt capacity or more, the utility shall, at the qualifying facility's or the utility's request, provide wheeling or exchange agreements wherever practicable to sell the qualifying facility's output to any other Minnesota utility having generation expansion anticipated or planned for the ensuing ten years. The commission shall establish the methods and procedures to insure that except for reasonable wheeling charges and line losses, the qualifying facility receives the full avoided energy and capacity costs of the utility ultimately receiving the output.

(d) The commission shall set rates for electricity generated by renewable energy.

Subd. 4a.Aggregation of meters.

(a) For the purpose of measuring electricity under subdivisions 3 and 3a, a public utility must aggregate for billing purposes a customer's designated meter with one or more aggregated meters if a customer requests that it do so. To qualify for aggregation under this subdivision, a meter must be owned by the customer requesting the aggregation, must be located on contiguous property owned by the customer requesting the aggregation, and the total of all aggregated meters must be subject to the size limitation in this section.

(b) A public utility must comply with a request by a customer-generator to aggregate additional meters within 90 days. The specific meters must be identified at the time of the request. In the event that more than one meter is identified, the customer must designate the rank order for the aggregated meters to which the net metered credits are to be applied. At least 60 days prior to the beginning of the next annual billing period, a customer may amend the rank order of the aggregated meters, subject to this subdivision.

(c) The aggregation of meters applies only to charges that use kilowatt-hours as the billing determinant. All other charges applicable to each meter account shall be billed to the customer.

(d) A public utility will first apply the kilowatt-hour credit to the charges for the designated meter and then to the charges for the aggregated meters in the rank order specified by the customer. If the net metered facility supplies more electricity to the public utility than the energy usage recorded by the customer-generator's designated and aggregated meters during a monthly billing period, the public utility shall apply credits to the customer's next monthly bill for the excess kilowatt-hours.

(e) With the commission's prior approval, a public utility may charge the customer-generator requesting to aggregate meters a reasonable fee to cover the administrative costs incurred in implementing the costs of this subdivision, pursuant to a tariff approved by the commission for a public utility.

Subd. 4b.Limiting cumulative generation.

The commission may limit the cumulative generation of net metered facilities under subdivisions 3 and 3a. A public utility may request the commission to limit the cumulative generation of net metered facilities under subdivisions 3 and 3a upon a showing that such generation has reached four percent of the public utility's annual retail electricity sales. The commission may limit additional net metering obligations under this subdivision only after providing notice and opportunity for public comment. In determining whether to limit additional net metering obligations under this subdivision, the commission shall consider:

(1) the environmental and other public policy benefits of net metered facilities;

(2) the impact of net metered facilities on electricity rates for customers without net metered systems;

(3) the effects of net metering on the reliability of the electric system;

(4) technical advances or technical concerns; and

(5) other statutory obligations imposed on the commission or on a utility.

The commission may limit additional net metering obligations under clauses (2) to (4) only if it determines that additional net metering obligations would cause significant rate impact, require significant measures to address reliability, or raise significant technical issues.

Subd. 4c.Individual system capacity limits.

(a) A public utility that provides retail electric service may require customers with a facility of 40-kilowatt capacity or more and participating in net metering and net billing to limit the total generation capacity of individual distributed generation systems by either:

(1) for wind generation systems, limiting the total generation system capacity kilowatt alternating current to 120 percent of the customer's on-site maximum electric demand; or

(2) for solar photovoltaic and other distributed generation, limiting the total generation system annual energy production kilowatt hours alternating current to 120 percent of the customer's on-site annual electric energy consumption.

(b) Limits under paragraph (a) must be based on standard 15-minute intervals, measured during the previous 12 calendar months, or on a reasonable estimate of the average monthly maximum demand or average annual consumption if the customer has either:

(i) less than 12 calendar months of actual electric usage; or

(ii) no demand metering available.

Subd. 5.Dispute; resolution.

In the event of disputes between an electric utility and a qualifying facility, either party may request a determination of the issue by the commission. In any such determination, the burden of proof shall be on the utility. The commission in its order resolving each such dispute shall require payments to the prevailing party of the prevailing party's costs, disbursements, and reasonable attorneys' fees, except that the qualifying facility will be required to pay the costs, disbursements, and attorneys' fees of the utility only if the commission finds that the claims of the qualifying facility in the dispute have been made in bad faith, or are a sham, or are frivolous.

Subd. 6.Rules and uniform contract.

(a) The commission shall promulgate rules to implement the provisions of this section. The commission shall also establish a uniform statewide form of contract for use between utilities and a net metered or qualifying facility having less than 1,000-kilowatt capacity if interconnected to a public utility or less than 40-kilowatt capacity if interconnected to a cooperative electric association or municipal utility.

(b) The commission shall require the qualifying facility to provide the utility with reasonable access to the premises and equipment of the qualifying facility if the particular configuration of the qualifying facility precludes disconnection or testing of the qualifying facility from the utility side of the interconnection with the utility remaining responsible for its personnel.

(c) The uniform statewide form of contract shall be applied to all new and existing interconnections established between a utility and a net metered or qualifying facility having less than 40-kilowatt capacity, except that existing contracts may remain in force until terminated by mutual agreement between both parties.

Subd. 7.

[Repealed, 1994 c 465 art 1 s 27]

Subd. 8.Interconnection required; obligation for costs.

(a) Utilities shall be required to interconnect with a qualifying facility that offers to provide available energy or capacity and that satisfies the requirements of this section.

(b) Nothing contained in this section shall be construed to excuse the qualifying facility from any obligation for costs of interconnection and wheeling in excess of those normally incurred by the utility for customers with similar load characteristics who are not cogenerators or small power producers, or from any fixed charges normally assessed such nongenerating customers.

Subd. 9.Municipal electric utility.

For purposes of this section only, except subdivision 5, and with respect to municipal electric utilities only, the term "commission" means the governing body of each municipal electric utility that adopts and has in effect rules implementing this section which are consistent with the rules adopted by the Minnesota Public Utilities Commission under subdivision 6. As used in this subdivision, the governing body of a municipal electric utility means the city council of that municipality; except that, if another board, commission, or body is empowered by law or resolution of the city council or by its charter to establish and regulate rates and days for the distribution of electric energy within the service area of the city, that board, commission, or body shall be considered the governing body of the municipal electric utility.

Subd. 10.Alternative tariff; compensation for resource value.

(a) A public utility may apply for commission approval for an alternative tariff that compensates customers through a bill credit mechanism for the value to the utility, its customers, and society for operating distributed solar photovoltaic resources interconnected to the utility system and operated by customers primarily for meeting their own energy needs.

(b) If approved, the alternative tariff shall apply to customers' interconnections occurring after the date of approval. The alternative tariff is in lieu of the applicable rate under subdivisions 3 and 3a.

(c) The commission shall after notice and opportunity for public comment approve the alternative tariff provided the utility has demonstrated the alternative tariff:

(1) appropriately applies the methodology established by the department and approved by the commission under this subdivision;

(2) includes a mechanism to allow recovery of the cost to serve customers receiving the alternative tariff rate;

(3) charges the customer for all electricity consumed by the customer at the applicable rate schedule for sales to that class of customer;

(4) credits the customer for all electricity generated by the solar photovoltaic device at the distributed solar value rate established under this subdivision;

(5) applies the charges and credits in clauses (3) and (4) to a monthly bill that includes a provision so that the unused portion of the credit in any month or billing period shall be carried forward and credited against all charges. In the event that the customer has a positive balance after the 12-month cycle ending on the last day in February, that balance will be eliminated and the credit cycle will restart the following billing period beginning on March 1;

(6) complies with the size limits specified in subdivision 3a;

(7) complies with the interconnection requirements under section 216B.1611; and

(8) complies with the standby charge requirements in subdivision 3a, paragraph (b).

(d) A utility must provide to the customer the meter and any other equipment needed to provide service under the alternative tariff.

(e) The department must establish the distributed solar value methodology in paragraph (c), clause (1), no later than January 31, 2014. The department must submit the methodology to the commission for approval. The commission must approve, modify with the consent of the department, or disapprove the methodology within 60 days of its submission. When developing the distributed solar value methodology, the department shall consult stakeholders with experience and expertise in power systems, solar energy, and electric utility ratemaking regarding the proposed methodology, underlying assumptions, and preliminary data.

(f) The distributed solar value methodology established by the department must, at a minimum, account for the value of energy and its delivery, generation capacity, transmission capacity, transmission and distribution line losses, and environmental value. The department may, based on known and measurable evidence of the cost or benefit of solar operation to the utility, incorporate other values into the methodology, including credit for locally manufactured or assembled energy systems, systems installed at high-value locations on the distribution grid, or other factors.

(g) The credit for distributed solar value applied to alternative tariffs approved under this section shall represent the present value of the future revenue streams of the value components identified in paragraph (f).

(h) The utility shall recalculate the alternative tariff on an annual cycle, and shall file the recalculated alternative tariff with the commission for approval.

(i) Renewable energy credits for solar energy credited under this subdivision belong to the electric utility providing the credit.

(j) The commission may not authorize a utility to charge an alternative tariff rate that is lower than the utility's applicable retail rate until three years after the commission approves an alternative tariff for the utility.

(k) A utility must enter into a contract with an owner of a solar photovoltaic device receiving an alternative tariff rate under this section that has a term of at least 20 years, unless a shorter term is agreed to by the parties.

(l) An owner of a solar photovoltaic device receiving an alternative tariff rate under this section must be paid the same rate per kilowatt-hour generated each year for the term of the contract.

216B.1641 COMMUNITY SOLAR GARDEN.

(a) The public utility subject to section 116C.779 shall file by September 30, 2013, a plan with the commission to operate a community solar garden program which shall begin operations within 90 days after commission approval of the plan. Other public utilities may file an application at their election. The community solar garden program must be designed to offset the energy use of not less than five subscribers in each community solar garden facility of which no single subscriber has more than a 40 percent interest. The owner of the community solar garden may be a public utility or any other entity or organization that contracts to sell the output from the community solar garden to the utility under section 216B.164. There shall be no limitation on the number or cumulative generating capacity of community solar garden facilities other than the limitations imposed under section 216B.164, subdivision 4c, or other limitations provided in law or regulations.

(b) A solar garden is a facility that generates electricity by means of a ground-mounted or roof-mounted solar photovoltaic device whereby subscribers receive a bill credit for the electricity generated in proportion to the size of their subscription. The solar garden must have a nameplate capacity of no more than one megawatt. Each subscription shall be sized to represent at least 200 watts of the community solar garden's generating capacity and to supply, when combined with other distributed generation resources serving the premises, no more than 120 percent of the average annual consumption of electricity by each subscriber at the premises to which the subscription is attributed.

(c) The solar generation facility must be located in the service territory of the public utility filing the plan. Subscribers must be retail customers of the public utility located in the same county or a county contiguous to where the facility is located.

(d) The public utility must purchase from the community solar garden all energy generated by the solar garden. The purchase shall be at the rate calculated under section 216B.164, subdivision 10, or, until that rate for the public utility has been approved by the commission, the applicable retail rate. A solar garden is eligible for any incentive programs offered under either section 116C.7792 or section 216C.415. A subscriber's portion of the purchase shall be provided by a credit on the subscriber's bill.

(e) The commission may approve, disapprove, or modify a community solar garden program. Any plan approved by the commission must:

(1) reasonably allow for the creation, financing, and accessibility of community solar gardens;

(2) establish uniform standards, fees, and processes for the interconnection of community solar garden facilities that allow the utility to recover reasonable interconnection costs for each community solar garden;

(3) not apply different requirements to utility and nonutility community solar garden facilities;

(4) be consistent with the public interest;

(5) identify the information that must be provided to potential subscribers to ensure fair disclosure of future costs and benefits of subscriptions;

(6) include a program implementation schedule;

(7) identify all proposed rules, fees, and charges; and

(8) identify the means by which the program will be promoted.

(f) Notwithstanding any other law, neither the manager of nor the subscribers to a community solar garden facility shall be considered a utility solely as a result of their participation in the community solar garden facility.

(g) Within 180 days of commission approval of a plan under this section, a utility shall begin crediting subscriber accounts for each community solar garden facility in its service territory, and shall file with the commissioner of commerce a description of its crediting system.

(h) For the purposes of this section, the following terms have the meanings given:

(1) "subscriber" means a retail customer of a utility who owns one or more subscriptions of a community solar garden facility interconnected with that utility; and

(2) "subscription" means a contract between a subscriber and the owner of a solar garden.

216B.1645 POWER PURCHASE CONTRACT OR INVESTMENT.

Subdivision 1.Commission authority.

Upon the petition of a public utility, the Public Utilities Commission shall approve or disapprove power purchase contracts, investments, or expenditures entered into or made by the utility to satisfy the wind and biomass mandates contained in sections 216B.169, 216B.2423, and 216B.2424, and to satisfy the renewable energy objectives and standards set forth in section 216B.1691, including reasonable investments and expenditures made to:

(1) transmit the electricity generated from sources developed under those sections that is ultimately used to provide service to the utility's retail customers, including studies necessary to identify new transmission facilities needed to transmit electricity to Minnesota retail customers from generating facilities constructed to satisfy the renewable energy objectives and standards, provided that the costs of the studies have not been recovered previously under existing tariffs and the utility has filed an application for a certificate of need or for certification as a priority project under section 216B.2425 for the new transmission facilities identified in the studies;

(2) provide storage facilities for renewable energy generation facilities that contribute to the reliability, efficiency, or cost-effectiveness of the renewable facilities; or

(3) develop renewable energy sources from the account required in section 116C.779.

Subd. 2.Cost recovery.

The expenses incurred by the utility over the duration of the approved contract or useful life of the investment and expenditures made pursuant to section 116C.779 shall be recoverable from the ratepayers of the utility, to the extent they are not offset by utility revenues attributable to the contracts, investments, or expenditures. Upon petition by a public utility, the commission shall approve or approve as modified a rate schedule providing for the automatic adjustment of charges to recover the expenses or costs approved by the commission under subdivision 1, which, in the case of transmission expenditures, are limited to the portion of actual transmission costs that are directly allocable to the need to transmit power from the renewable sources of energy. The commission may not approve recovery of the costs for that portion of the power generated from sources governed by this section that the utility sells into the wholesale market.

Subd. 2a.Cost recovery for utility's renewable facilities.

(a) A utility may petition the commission to approve a rate schedule that provides for the automatic adjustment of charges to recover prudently incurred investments, expenses, or costs associated with facilities constructed, owned, or operated by a utility to satisfy the requirements of section 216B.1691, provided those facilities were previously approved by the commission under section 216B.2422 or 216B.243, or were determined by the commission to be reasonable and prudent under section 216B.243, subdivision 9. For facilities not subject to review by the commission under section 216B.2422 or 216B.243, a utility shall petition the commission for eligibility for cost recovery under this section prior to requesting cost recovery for the facility. The commission may approve, or approve as modified, a rate schedule that:

(1) allows a utility to recover directly from customers on a timely basis the costs of qualifying renewable energy projects, including:

(i) return on investment;

(ii) depreciation;

(iii) ongoing operation and maintenance costs;

(iv) taxes; and

(v) costs of transmission and other ancillary expenses directly allocable to transmitting electricity generated from a project meeting the specifications of this paragraph;

(2) provides a current return on construction work in progress, provided that recovery of these costs from Minnesota ratepayers is not sought through any other mechanism;

(3) allows recovery of other expenses incurred that are directly related to a renewable energy project, including expenses for energy storage, provided that the utility demonstrates to the commission's satisfaction that the expenses improve project economics, ensure project implementation, advance research and understanding of how storage devices may improve renewable energy projects, or facilitate coordination with the development of transmission necessary to transport energy produced by the project to market;

(4) allocates recoverable costs appropriately between wholesale and retail customers;

(5) terminates recovery when costs have been fully recovered or have otherwise been reflected in a utility's rates.

(b) A petition filed under this subdivision must include:

(1) a description of the facilities for which costs are to be recovered;

(2) an implementation schedule for the facilities;

(3) the utility's costs for the facilities;

(4) a description of the utility's efforts to ensure that costs of the facilities are reasonable and were prudently incurred; and

(5) a description of the benefits of the project in promoting the development of renewable energy in a manner consistent with this chapter.

Subd. 3.Applicability to recovery of other costs.

Nothing in this section shall be construed to determine the manner or extent to which revenues derived from other generation facilities of the utility may be considered in determining the recovery of the approved cost or expenses associated with the mandated contracts, investments, or expenditures in the event there is retail competition for electric energy.

Subd. 4.Settlement with Mdewakanton Dakota Tribal Council at Prairie Island.

The commission shall approve a rate schedule providing for the automatic adjustment of charges to recover the costs or expenses of a settlement between the public utility that owns the Prairie Island nuclear generation facility and the Mdewakanton Dakota Tribal Council at Prairie Island, resolving outstanding disputes regarding the provisions of Laws 1994, chapter 641, article 1, section 4. The settlement must provide for annual payments, not to exceed $2,500,000 annually, by the public utility to the Prairie Island Indian Community, to be used for, among other purposes, acquiring up to 1,500 contiguous or noncontiguous acres of land in Minnesota within 50 miles of the tribal community's reservation at Prairie Island to be taken into trust by the federal government for the benefit of the tribal community for housing and other residential purposes. The legislature acknowledges that the intent to purchase land by the tribe for relocation purposes is part of the settlement agreement and Laws 2003, First Special Session chapter 11. However, the state, through the governor, reserves the right to support or oppose any particular application to place land in trust status.

216B.1646 RATE REDUCTION; PROPERTY TAX REDUCTION.

(a) The commission shall, by any method the commission finds appropriate, reduce the rates each electric utility subject to rate regulation by the commission charges its customers to reflect, on an ongoing basis, the amount by which each utility's property tax on the personal property of its electric system from taxes payable in 2001 to taxes payable in 2002 is reduced. The commission must ensure that, to the extent feasible, each dollar of personal property tax reduction allocated to Minnesota consumers retroactive to January 1, 2002, results in a dollar of savings to the utility's customers. A utility may voluntarily pass on any additional property tax savings allocated in the same manner as approved by the commission under this paragraph.

(b) By April 10, 2002, each utility shall submit a filing to the commission containing:

(1) certified information regarding the utility's property tax savings allocated to Minnesota retail customers; and

(2) a proposed method of passing these savings on to Minnesota retail customers.

The utility shall provide the information in clause (1) to the commissioner of revenue at the same time. The commissioner shall notify the commission within 30 days as to the accuracy of the property tax data submitted by the utility.

(c) For purposes of this section, "personal property" means tools, implements, and machinery of the generating plant. It does not apply to transformers, transmission lines, distribution lines, or any other tools, implements, and machinery that are part of an electric substation, wherever located.

216B.165 [Repealed, 2007 c 136 art 3 s 7]

216B.166 COGENERATING POWER PLANT.

Subdivision 1.Findings.

The legislature finds and declares that significant public benefits may be derived from the cogeneration of electrical and thermal energy and that cogenerated district heating may result in improved utilization and conservation of fuel, the substitution of coal for scarce oil and natural gas, the substitution of domestic fuel for imported fuel, and the establishment of a reliable, competitively priced heat source. Since the cost of cogenerated thermal energy is dependent upon the method used to allocate costs between the production of electric and thermal energy at a power plant, and because the method of cost allocation can be a significant factor in determining investment in district heating, it is necessary to develop cost allocation methods rapidly.

Subd. 2.Definitions.

For the purpose of this section, the following terms shall have the meanings given.

(a) "Cogeneration" means a combined process whereby electrical and thermal energy are simultaneously produced by a public utility power plant.

(b) "District heating" means a process whereby thermal energy is distributed within a community for use as a primary heat source.

(c) "District heating utility" means any person, corporation, or other legal entity which owns and operates a facility for district heating.

Subd. 3.Cost allocation.

The methods used to allocate or assign costs between electrical and thermal energy produced by cogeneration power plants owned by public utilities shall be consistent with the following principles:

(a) The method used shall result in a cost per unit of electricity which is no greater than the cost per unit which would exist if the power plants owned by the public utility had been normally constructed and operated without cogenerating capability.

(b) Costs which the public utility incurs for the exclusive benefit of the district heating utility, including but not limited to backup and peaking facilities, shall be assigned to thermal energy produced by cogeneration.

(c) The methods and procedures may be different for retrofitted than for new cogeneration power plants.

(d) The methods should encourage cogeneration while preventing subsidization by electric consumers so that both heating and electricity consumers are treated fairly and equitably with respect to the costs and benefits of cogeneration.

History:

1981 c 334 s 9

216B.167 PERFORMANCE-BASED GAS PURCHASING PLAN.

Subdivision 1.Plan approval; commission findings.

A public utility that furnishes natural gas may petition the commission for approval of a performance-based gas purchasing plan under this section. The commission may approve a plan if it finds that:

(1) the plan provides incentives for the utility to achieve lower natural gas costs than would have been achieved in the absence of the plan, as measured by the benchmarks established in clause (3), by linking financial rewards and penalties to natural gas costs;

(2) the potential benefits of the plan apply, at a minimum, to each customer class purchasing firm natural gas service from the utility;

(3) the plan establishes one or more benchmarks against which actual natural gas costs will be measured and the benchmarks reflect relevant market conditions and represent reasonable and achievable natural gas costs in Minnesota for the term of the plan; and

(4) the plan provides that the utility cannot curtail or interrupt service to any customer class purchasing firm natural gas service during the term of the plan except for causes outside the reasonable control of the utility or causes not directly related to the gas purchasing practices of the utility.

Subd. 2.Sharing mechanism.

A plan must include a mechanism through which the utility shares with its customers the difference between actual natural gas costs and the plan's benchmark costs during the term of the plan. A plan must provide details of the sharing mechanism and may include an allowed level of costs above and below the benchmark before any sharing is to take place. The commission must determine an appropriate percentage of the difference between the benchmark and actual natural gas costs to be shared between customers and the utility. The sharing mechanism shall be implemented annually under section 216B.16, subdivision 7a. Financial rewards or penalties under the plan shall not be considered in the determination of the utility's revenue requirements in a general rate case pursuant to section 216B.16.

Subd. 3.Reliability of service.

A plan must allow for the imposition of penalties if the standard for reliability of service established in subdivision 1, clause (4), is not met.

Subd. 4.Plan evaluation.

A plan must include an evaluation process and mechanism that is reasonable and capable of supporting a full review of the utility's performance under the plan. The commission shall evaluate the various customer and utility impacts of a plan based on this evaluation process and mechanism, including the impact on customer bills over time, the impact on utility revenues, and the effectiveness of the plan in meeting the purposes contained in subdivision 1. The evaluation must occur within a reasonable time following the end of the plan.

Subd. 5.Annual report.

The utility shall provide an annual report to the commission documenting its performance in meeting the requirements of the plan. Upon review of this report, the commission shall determine and approve rewards or penalties as provided in the plan.

Subd. 6.Adoption.

A plan may be filed and approved within a miscellaneous tariff filing pursuant to section 216B.16. The commission may approve, reject, or modify the plan in a manner which meets the requirements of this section. An approved plan is effective for a period of not less than two years unless:

(1) the plan is withdrawn by the utility within 30 days of a final appealable order approving the plan; or

(2) the commission, after notice and hearing, rescinds or amends its order approving the plan.

Subd. 7.

[Repealed, 1999 c 21 s 1]

Subd. 8.

[Repealed, 1999 c 21 s 1]

History:

1995 c 17 s 1

216B.1675 PERFORMANCE REGULATION PLAN FOR GAS UTILITY SERVICE.

Subdivision 1.Purpose.

Performance-based regulation plans for public utilities offering natural gas services are authorized in order to provide quality service at rates that can reasonably and reliably be expected to be materially lower than rates would be under current regulation and to reduce the cost of regulation. Performance-based regulation plans are intended to provide the utility with increased earnings for efficient performance and decreased earnings for inefficient performance.

Subd. 2.Petition.

A public utility that furnishes natural gas service may petition and file with the commission for its approval a performance regulation plan pursuant to this section. The plan applies to the utility's rates for providing natural gas distribution service, excluding the portion of the rates recovering the cost of natural gas supplies. If adopted, the plan must apply to all of the utility's customers, except that nothing in this section requires the utility to adjust the rates collected from customers receiving service under tariffs authorized by sections 216B.16, subdivision 15, and 216B.163. A petition may be filed:

(1) as part of a general rate filing pursuant to section 216B.16, in which case the time provided for the commission to suspend rates and make a final determination shall be extended by two months; or

(2) as a miscellaneous tariff filing pursuant to section 216B.16, in which case the commission shall, within 120 days of the date of the filing, determine whether the utility's current rates are reasonable based on financial information for the most recent calendar year, amended to reflect appropriate regulatory adjustments. If the commission cannot resolve all material issues concerning the reasonableness of the utility's current rates to its satisfaction, it shall dismiss the filing. If the filing is not dismissed, the commission shall issue its decision on the plan within ten months from the date of the filing. The rates at the beginning of the plan shall be the same as the rates on file with the commission prior to the filing.

Subd. 3.Plan contents.

The commission may approve a performance regulation plan for natural gas distribution services upon finding that the plan:

(1) contains a benchmark or measure of gas distribution costs that is a reasonable and reliable predictor of the utility's rates for gas distribution service under cost-of-service regulation;

(2) ensures that rates for gas distribution services to customers under the plan will be materially lower than the rates would be under cost-of-service regulation as predicted by the benchmark in clause (1);

(3) links the utility's earnings to its performance by permitting higher utility earnings than under cost-of-service regulation only when the utility's performance is more efficient than the benchmark;

(4) can be reasonably and reliably expected to offer lower administrative costs than would otherwise be experienced under cost-of-service regulation;

(5) contains a reasonable limit on utility earnings;

(6) has adequate provisions to prevent the degradation of service quality; and

(7) provides for gathering of relevant data and evaluation of the plan's effect on rates, service quality, utility earnings, competition in providing natural gas, and regulatory costs.

Subd. 4.Rate change.

The initial rate adjustment under the plan may not be implemented for a minimum of 18 months following the final determination by the commission on the plan. The plan shall provide a methodology and procedures for changing rates thereafter not more frequently than on an annual basis. The commission may allow the utility to change rates to reflect material changes in cost due to compliance with government mandates provided that the cost is one that the commission would otherwise allow to be recovered in rates. Increases or decreases in revenues under the plan shall be applied on an equal percentage basis to each customer class, excluding the portion of the rate recovering the cost of natural gas supplies. Miscellaneous rate changes may be approved outside the operation of the plan.

Subd. 5.Acceptance of petition for full review.

Interested parties have, unless the commission otherwise orders, 45 days from the date a petition containing a proposed plan is filed to submit comments on whether the plan, as proposed, addresses each of the requirements of this section sufficiently to merit further consideration. If the commission does not dismiss the petition proposing a plan as insufficient within 120 days from the date of the filing, the petition shall be deemed accepted for filing. A petition accepted for filing shall not be presumed accepted for final adoption.

Subd. 6.Plan administration.

A plan must require the filing of information needed to administer the plan.

Subd. 7.Notice to customer.

The petitioning utility must provide notice of the proposed plan to its customers and to the governing body of each municipality and county in the area affected, along with a summary description of the plan provisions and a notice of the dates, times, and locations of any public meetings scheduled by the commission.

Subd. 8.Plan review; hearing; discovery.

In reviewing a proposed plan, the commission shall:

(1) conduct public meetings that it considers appropriate; and

(2) grant discovery, as appropriate.

Subd. 9.Commission findings.

The commission shall issue findings concerning the appropriateness of the proposed plan. The commission may approve, reject, or modify the plan in a manner which meets the requirements of this section. An approved or modified plan becomes effective unless the plan is withdrawn by the utility within 30 days of a final appealable order. If the utility withdraws an approved or modified plan, all of the administrative costs related to the plan that are charged by the commission or the department to the utility may not be recovered from ratepayers in current or subsequent rates. A utility that withdraws an approved or modified plan may not file another plan under this section for a period of one year following the withdrawal of the plan.

Subd. 10.Plan term; renewal.

The plan shall specify its term, which shall not be less than three years. Not less than six months before the completion of the term of an approved plan, the commission shall, at the request of the utility, commence a review of the plan to determine whether to renew the plan for an additional term. The commission may approve, reject, or modify the renewal plan in a manner that meets the requirements of this section. A plan approved or modified under this subdivision becomes effective unless the plan is withdrawn by the utility within 30 days of a final appealable order.

Subd. 11.Plan termination.

On its own motion or upon the petition of any party other than the utility, the commission may initiate an investigation to determine whether to terminate the plan. The commission shall issue findings on the investigation within 120 days. If the commission finds that the plan has failed to meet the requirements of this section and is inconsistent with the public interest, it shall terminate the plan and may order the utility to initiate any proceedings necessary to correct the failure of the plan, including but not limited to, filing a general rate proceeding under section 216B.16. The utility must be allowed at least 120 days after the date of the commission's order to initiate the general rate proceeding.

Subd. 12.Plan evaluation.

A plan must include an evaluation process and mechanism that is reasonable and capable of supporting a full review of the utility's performance under the plan. The commission shall evaluate the various customer and utility impacts of a plan based on this evaluation process and mechanism, including the impact on customer bills and service quality, over time, the impact on utility revenues, and the effectiveness of the plan in meeting the purposes of this section. The evaluation must occur within a reasonable time following the end of the plan.

Subd. 13.General evaluation.

The commission shall evaluate the effectiveness of all plans approved under this section and submit its findings to the legislature by January 1, 2012.

216B.168 [ Expired, 1993 c 254 s 1]

216B.1681 CURTAILMENT PAYMENTS.

The commission shall conduct a study of curtailment payments for wind energy projects to assess whether utilities are unduly discriminating among project ownership structures in regard to the contractual availability of curtailment payments. The commission shall submit the study to the chairs and ranking minority members of the senate and house of representatives committees with primary jurisdiction over energy policy by January 15, 2008.

216B.169 RENEWABLE AND HIGH-EFFICIENCY ENERGY RATE OPTIONS.

Subdivision 1.Definitions.

For the purposes of this section, the following terms have the meanings given them.

(a) "Utility" means a public utility, municipal utility, or cooperative electric association providing electric service at retail to Minnesota consumers.

(b) "Renewable energy" has the meaning given in section 216B.2422, subdivision 1, paragraph (c).

(c) "High-efficiency, low-emissions, distributed generation" means a distributed generation facility of no more than ten megawatts of interconnected capacity that is certified by the commissioner under subdivision 3 as a high-efficiency, low-emissions facility.

Subd. 2.Renewable and high-efficiency energy rate options.

(a) A utility may offer its customers one or more options that allow a customer to determine that a certain amount of the electricity generated or purchased on behalf of the customer is renewable energy or energy generated by high-efficiency, low-emissions, distributed generation such as fuel cells and microturbines fueled by a renewable fuel.

(b) Rates charged to customers must be calculated using the utility's cost of acquiring the energy for the customer and must:

(1) reflect the difference between the cost of generating or purchasing the additional renewable energy and the cost that would otherwise be attributed to the customer for the same amount of energy based on the utility's mix of renewable and nonrenewable energy sources; and

(2) be distributed on a per kilowatt-hour basis among all customers who choose to participate in the program.

(c) The utility may acquire the energy demanded by customers, in whole or in part, through procuring or generating the renewable energy directly, or through the purchase of credits from a provider that has received certification of eligible power supply pursuant to subdivision 3.

(d) For the purposes of this section, "renewable energy" has the meaning given to "eligible energy technology" in section 216B.1691, subdivision 1, paragraph (a), but does not include energy recovered from combustion of mixed municipal solid waste or refuse-derived fuel from mixed municipal solid waste.

Subd. 3.Certification and tradable credits.

(a) The commissioner shall certify a power supply or supplies as eligible to satisfy customer requirements under this section upon finding:

(1) the power supply is renewable energy or energy generated by high-efficiency, low-emissions, distributed generation; and

(2) the sales arrangements of energy from the supplies are such that the power supply is only sold once to retail consumers.

(b) To facilitate compliance with this section, the commission may, by order, establish a program for tradable credits for eligible power supplies.

History:

2001 c 212 art 8 s 2; 2007 c 3 s 3; 2009 c 110 s 12,38

216B.1691 RENEWABLE ENERGY OBJECTIVES.

Subdivision 1.Definitions.

(a) Unless otherwise specified in law, "eligible energy technology" means an energy technology that generates electricity from the following renewable energy sources:

(1) solar;

(2) wind;

(3) hydroelectric with a capacity of less than 100 megawatts;

(4) hydrogen, provided that after January 1, 2010, the hydrogen must be generated from the resources listed in this paragraph; or

(5) biomass, which includes, without limitation, landfill gas; an anaerobic digester system; the predominantly organic components of wastewater effluent, sludge, or related by-products from publicly owned treatment works, but not including incineration of wastewater sludge to produce electricity; and an energy recovery facility used to capture the heat value of mixed municipal solid waste or refuse-derived fuel from mixed municipal solid waste as a primary fuel.

(b) "Electric utility" means a public utility providing electric service, a generation and transmission cooperative electric association, a municipal power agency, or a power district.

(c) "Total retail electric sales" means the kilowatt-hours of electricity sold in a year by an electric utility to retail customers of the electric utility or to a distribution utility for distribution to the retail customers of the distribution utility. "Total retail electric sales" does not include the sale of hydroelectricity supplied by a federal power marketing administration or other federal agency, regardless of whether the sales are directly to a distribution utility or are made to a generation and transmission utility and pooled for further allocation to a distribution utility.

Subd. 2.Eligible energy objectives.

Each electric utility shall make a good faith effort to generate or procure sufficient electricity generated by an eligible energy technology to provide its retail consumers, or the retail customers of a distribution utility to which the electric utility provides wholesale electric service, so that commencing in 2005, at least one percent of the electric utility's total retail electric sales to retail customers in Minnesota is generated by eligible energy technologies and seven percent of the electric utility's total retail electric sales to retail customers in Minnesota by 2010 is generated by eligible energy technologies.

Subd. 2a.Eligible energy technology standard.

(a) Except as provided in paragraph (b), each electric utility shall generate or procure sufficient electricity generated by an eligible energy technology to provide its retail customers in Minnesota, or the retail customers of a distribution utility to which the electric utility provides wholesale electric service, so that at least the following standard percentages of the electric utility's total retail electric sales to retail customers in Minnesota are generated by eligible energy technologies by the end of the year indicated:

(1) 2012 12 percent
(2) 2016 17 percent
(3) 2020 20 percent
(4) 2025 25 percent.

(b) An electric utility that owned a nuclear generating facility as of January 1, 2007, must meet the requirements of this paragraph rather than paragraph (a). An electric utility subject to this paragraph must generate or procure sufficient electricity generated by an eligible energy technology to provide its retail customers in Minnesota or the retail customer of a distribution utility to which the electric utility provides wholesale electric service so that at least the following percentages of the electric utility's total retail electric sales to retail customers in Minnesota are generated by eligible energy technologies by the end of the year indicated:

(1) 2010 15 percent
(2) 2012 18 percent
(3) 2016 25 percent
(4) 2020 30 percent.

Of the 30 percent in 2020, at least 25 percent must be generated by solar energy or wind energy conversion systems and the remaining five percent by other eligible energy technology. Of the 25 percent that must be generated by wind or solar, no more than one percent may be solar generated and the remaining 24 percent or greater must be wind generated.

Subd. 2b.Modification or delay of standard.

(a) The commission shall modify or delay the implementation of a standard obligation, in whole or in part, if the commission determines it is in the public interest to do so. The commission, when requested to modify or delay implementation of a standard, must consider:

(1) the impact of implementing the standard on its customers' utility costs, including the economic and competitive pressure on the utility's customers;

(2) the effects of implementing the standard on the reliability of the electric system;

(3) technical advances or technical concerns;

(4) delays in acquiring sites or routes due to rejection or delays of necessary siting or other permitting approvals;

(5) delays, cancellations, or nondelivery of necessary equipment for construction or commercial operation of an eligible energy technology facility;

(6) transmission constraints preventing delivery of service; and

(7) other statutory obligations imposed on the commission or a utility.

The commission may modify or delay implementation of a standard obligation under clauses (1) to (3) only if it finds implementation would cause significant rate impact, requires significant measures to address reliability, or raises significant technical issues. The commission may modify or delay implementation of a standard obligation under clauses (4) to (6) only if it finds that the circumstances described in those clauses were due to circumstances beyond an electric utility's control and make compliance not feasible.

(b) When considering whether to delay or modify implementation of a standard obligation, the commission must give due consideration to a preference for electric generation through use of eligible energy technology and to the achievement of the standards set by this section.

(c) An electric utility requesting a modification or delay in the implementation of a standard must file a plan to comply with its standard obligation in the same proceeding that it is requesting the delay.

Subd. 2c.Use of integrated resource planning process.

The commission may exercise its authority under subdivision 2b to modify or delay implementation of a standard obligation as part of an integrated resource planning proceeding under section 216B.2422. The commission's authority must be exercised according to subdivision 2b. The order to delay or modify shall not be considered advisory with respect to any electric utility. This subdivision is in addition to and does not limit the commission's authority to modify or delay implementation of a standard obligation in other proceedings before the commission.

Subd. 2d.Commission order.

The commission shall issue necessary orders detailing the criteria and standards by which it will measure an electric utility's efforts to meet the renewable energy objectives of subdivision 2 to determine whether the utility is making the required good faith effort. In this order, the commission shall include criteria and standards that protect against undesirable impacts on the reliability of the utility's system and economic impacts on the utility's ratepayers and that consider technical feasibility.

Subd. 2e.Rate impact of standard compliance; report.

Each electric utility must submit to the commission and the legislative committees with primary jurisdiction over energy policy a report containing an estimation of the rate impact of activities of the electric utility necessary to comply with this section. In consultation with the Department of Commerce, the commission shall determine a uniform reporting system to ensure that individual utility reports are consistent and comparable, and shall, by order, require each electric utility subject to this section to use that reporting system. The rate impact estimate must be for wholesale rates and, if the electric utility makes retail sales, the estimate shall also be for the impact on the electric utility's retail rates. Those activities include, without limitation, energy purchases, generation facility acquisition and construction, and transmission improvements. An initial report must be submitted within 150 days of May 28, 2011. After the initial report, a report must be updated and submitted as part of each integrated resource plan or plan modification filed by the electric utility under section 216B.2422. The reporting obligation of an electric utility under this subdivision expires December 31, 2025, for an electric utility subject to subdivision 2a, paragraph (a), and December 31, 2020, for an electric utility subject to subdivision 2a, paragraph (b).

Subd. 2f.Solar energy standard.

(a) In addition to the requirements of subdivisions 2a and 2b, each public utility shall generate or procure sufficient electricity generated by solar energy to serve its retail electricity customers in Minnesota so that by the end of 2020, at least 1.5 percent of the utility's total retail electric sales to retail customers in Minnesota is generated by solar energy. At least ten percent of the 1.5 percent goal must be met by solar energy generated by or procured from solar photovoltaic devices with a nameplate capacity of 20 kilowatts or less.

(b) The solar energy standard established in this subdivision is subject to all the provisions of this section governing a utility's standard obligation under subdivision 2a.

(c) It is an energy goal of the state of Minnesota that, by 2030, ten percent of the retail electric sales in Minnesota be generated by solar energy.

(d) For the purposes of calculating the total retail electric sales of a public utility under this subdivision, there shall be excluded retail electric sales to customers that are:

(1) an iron mining extraction and processing facility, including a scram mining facility as defined in Minnesota Rules, part 6130.0100, subpart 16; or

(2) a paper mill, wood products manufacturer, sawmill, or oriented strand board manufacturer.

Those customers may not have included in the rates charged to them by the public utility any costs of satisfying the solar standard specified by this subdivision.

(e) A public utility may not use energy used to satisfy the solar energy standard under this subdivision to satisfy its standard obligation under subdivision 2a. A public utility may not use energy used to satisfy the standard obligation under subdivision 2a to satisfy the solar standard under this subdivision.

(f) Notwithstanding any law to the contrary, a solar renewable energy credit associated with a solar photovoltaic device installed and generating electricity in Minnesota after August 1, 2013, but before 2020 may be used to meet the solar energy standard established under this subdivision.

(g) Beginning July 1, 2014, and each July 1 through 2020, each public utility shall file a report with the commission reporting its progress in achieving the solar energy standard established under this subdivision.

Subd. 3.Utility plans filed with commission.

(a) Each electric utility shall report on its plans, activities, and progress with regard to the objectives and standards of this section in its filings under section 216B.2422 or in a separate report submitted to the commission every two years, whichever is more frequent, demonstrating to the commission the utility's effort to comply with this section. In its resource plan or a separate report, each electric utility shall provide a description of:

(1) the status of the utility's renewable energy mix relative to the objective and standards;

(2) efforts taken to meet the objective and standards;

(3) any obstacles encountered or anticipated in meeting the objective or standards; and

(4) potential solutions to the obstacles.

(b) The commissioner shall compile the information provided to the commission under paragraph (a), and report to the chairs of the house of representatives and senate committees with jurisdiction over energy and environment policy issues as to the progress of utilities in the state, including the progress of each individual electric utility, in increasing the amount of renewable energy provided to retail customers, with any recommendations for regulatory or legislative action, by January 15 of each odd-numbered year.

Subd. 4.Renewable energy credits.

(a) To facilitate compliance with this section, the commission, by rule or order, shall establish by January 1, 2008, a program for tradable renewable energy credits for electricity generated by eligible energy technology. The credits must represent energy produced by an eligible energy technology, as defined in subdivision 1. Each kilowatt-hour of renewable energy credits must be treated the same as a kilowatt-hour of eligible energy technology generated or procured by an electric utility if it is produced by an eligible energy technology. The program must permit a credit to be used only once. The program must treat all eligible energy technology equally and shall not give more or less credit to energy based on the state where the energy was generated or the technology with which the energy was generated. The commission must determine the period in which the credits may be used for purposes of the program.

(b) In lieu of generating or procuring energy directly to satisfy the eligible energy technology objective or standard of this section, an electric utility may utilize renewable energy credits allowed under the program to satisfy the objective or standard.

(c) The commission shall facilitate the trading of renewable energy credits between states.

(d) The commission shall require all electric utilities to participate in a commission-approved credit-tracking system or systems. Once a credit-tracking system is in operation, the commission shall issue an order establishing protocols for trading credits.

(e) An electric utility subject to subdivision 2a, paragraph (b), may not sell renewable energy credits to an electric utility subject to subdivision 2a, paragraph (a), until 2021.

Subd. 5.Technology based on fuel combustion.

(a) Electricity produced by fuel combustion through fuel blending or co-firing under paragraph (b) may only count toward a utility's objectives or standards if the generation facility:

(1) was constructed in compliance with new source performance standards promulgated under the federal Clean Air Act, United States Code, title 42, section 7401 et seq., for a generation facility of that type; or

(2) employs the maximum achievable or best available control technology available for a generation facility of that type.

(b) An eligible energy technology may blend or co-fire a fuel listed in subdivision 1, paragraph (a), clause (5), with other fuels in the generation facility, but only the percentage of electricity that is attributable to a fuel listed in that clause can be counted toward an electric utility's renewable energy objectives.

Subd. 6.

[Repealed by amendment, 2007 c 3 s 1]

Subd. 7.Compliance.

The commission must regularly investigate whether an electric utility is in compliance with its good faith objective under subdivision 2 and standard obligation under subdivision 2a. If the commission finds noncompliance, it may order the electric utility to construct facilities, purchase energy generated by eligible energy technology, purchase renewable energy credits, or engage in other activities to achieve compliance. If an electric utility fails to comply with an order under this subdivision, the commission may impose a financial penalty on the electric utility in an amount not to exceed the estimated cost of the electric utility to achieve compliance. The penalty may not exceed the lesser of the cost of constructing facilities or purchasing credits. The commission must deposit financial penalties imposed under this subdivision in the energy and conservation account established in the special revenue fund under section 216B.241, subdivision 2a. This subdivision is in addition to and does not limit any other authority of the commission to enforce this section.

Subd. 8.Relation to other law.

This section does not limit the authority of the commission under any other law, including, without limitation, sections 216B.2422 and 216B.243.

Subd. 9.Local benefits.

The commission shall take all reasonable actions within its statutory authority to ensure this section is implemented to maximize benefits to Minnesota citizens, balancing factors such as local ownership of or participation in energy production, development and ownership of eligible energy technology facilities by independent power producers, Minnesota utility ownership of eligible energy technology facilities, the costs of energy generation to satisfy the renewable standard, and the reliability of electric service to Minnesotans.

Subd. 10.Utility acquisition of resources.

A competitive resource acquisition process established by the commission prior to June 1, 2007, shall not apply to a utility for the construction, ownership, and operation of generation facilities used to satisfy the requirements of this section unless, upon a finding that it is in the public interest, the commission issues an order on or after June 1, 2007, that requires compliance by a utility with a competitive resource acquisition process. A utility that owns a nuclear generation facility and intends to construct, own, or operate facilities under this section shall file with the commission on or before March 1, 2008, a renewable energy plan setting forth the manner in which the utility proposes to meet the requirements of this section, including a proposed schedule for purchasing renewable energy from C-BED and non-C-BED projects. The utility shall update the plan as necessary in its filing under section 216B.2422. The commission shall approve the plan unless it determines, after public hearing and comment, that the plan is not in the public interest. As part of its determination of public interest, the commission shall consider the plan's allocation of projects among C-BED, non-C-BED, and utility-owned projects, balancing the state's interest in:

(1) promoting the policy of economic development in rural areas through the development of renewable energy projects, as expressed in subdivision 9;

(2) maintaining the reliability of the state's electric power grid; and

(3) minimizing cost impacts on ratepayers.

216B.1692 EMISSIONS-REDUCTION RIDER.

Subdivision 1.Qualifying projects.

(a) Projects that may be approved for the emissions reduction-rate rider allowed in this section must:

(1) be installed on existing large electric generating power plants, as defined in section 216B.2421, subdivision 2, clause (1), that are located in the state and that are currently not subject to emissions limitations for new power plants under the federal Clean Air Act, United States Code, title 42, section 7401 et seq.;

(2) not increase the capacity of the existing electric generating power plant more than ten percent or more than 100 megawatts, whichever is greater; and

(3) result in the existing plant either:

(i) complying with applicable new source review standards under the federal Clean Air Act; or

(ii) emitting air contaminants at levels substantially lower than allowed for new facilities by the applicable new source performance standards under the federal Clean Air Act; or

(iii) reducing emissions from current levels at a unit to the lowest cost-effective level when, due to the age or condition of the generating unit, the public utility demonstrates that it would not be cost-effective to reduce emissions to the levels in item (i) or (ii).

(b) Notwithstanding paragraph (a), a project may be approved for the emission reduction rate rider allowed in this section if the project is to be installed on existing large electric generating power plants, as defined in section 216B.2421, subdivision 2, clause (1), that are located outside the state and are needed to comply with state or federal air quality standards, but only if the project has received an advance determination of prudence from the commission under section 216B.1695.

Subd. 1a.Exemption.

Subdivisions 2, 4, and 5, paragraph (c), clause (1), do not apply to projects qualifying under subdivision 1, paragraph (b).

Subd. 2.Proposal submission.

A public utility that intends to submit a proposal for an emissions-reduction rider under this section must submit to the commission, the department, the Pollution Control Agency, and interested parties its plans for emissions-reduction projects at its generating facilities. This submission must be made at least 60 days in advance of a petition for a rider and shall include:

(1) the priority order of emissions-reduction projects the utility plans to pursue at its generating facilities;

(2) the planned schedule for implementation;

(3) the analysis and considerations relied on by the public utility to develop that priority ranking;

(4) the alternative emissions-reduction projects considered, including but not limited to applications of the best available control technology and repowering with natural gas, and reasons for not pursuing them;

(5) the emissions reductions expected to be achieved by the projects and their relation to applicable standards for new facilities under the federal Clean Air Act, United States Code, title 42, section 7401 et seq.; and

(6) the general rationale and conclusions of the public utility in determining the priority ranking.

Subd. 3.Filing petition to recover project costs.

(a) A public utility may petition the commission for approval of an emissions-reduction rider to recover the costs of a qualifying emissions-reduction project outside of a general rate case proceeding under section 216B.16. In its filing, the public utility shall provide:

(1) a description of the planned emissions-reduction project;

(2) the activities involved in the project;

(3) a schedule for implementation;

(4) any analysis provided to the Pollution Control Agency regarding the project;

(5) an assessment of alternatives to the project, including costs, environmental impact, and operational issues;

(6) the proposed method of cost recovery;

(7) any proposed recovery above cost; and

(8) the projected emissions reductions from the project.

(b) Nothing in this section precludes a public utility or interested party from seeking commission guidelines for emissions-reduction rider filings; however, commission guidelines are not required as a prerequisite to a public utility-initiated filing.

Subd. 4.Environmental assessment.

The Pollution Control Agency shall evaluate the public utility's emissions-reduction project filing and provide the commission with:

(1) verification that the emissions-reduction project qualifies under subdivision 1;

(2) a description of the projected environmental benefits of the proposed project; and

(3) its assessment of the appropriateness of the proposed project.

Subd. 5.Proposal approval.

(a) After receiving the Pollution Control Agency's environmental assessment, the commission shall allow opportunity for written and oral comment on the proposed emissions reduction-rate rider proposal. The commission must assess the costs of an emissions-reduction project on a stand-alone basis and may approve, modify, or reject the proposed emissions-reduction rider. In making its determination, the commission shall consider whether the project, proposed cost recovery, and any proposed recovery above cost appropriately achieves environmental benefits without unreasonable consumer costs.

(b) The commission may approve a rider that:

(1) allows the utility to recover costs of qualifying emissions-reduction projects net of revenues attributable to the project;

(2) allows an appropriate return on investment associated with qualifying emissions-reduction projects at the level established in the public utility's last general rate case;

(3) allocates project costs appropriately between wholesale and retail customers;

(4) provides a mechanism for recovery above cost, if necessary to improve the overall economics of the qualifying projects to ensure implementation;

(5) recovers costs from retail customer classes in proportion to class energy consumption; and

(6) terminates recovery once the costs of qualifying projects have been fully recovered.

(c) The commission must not approve an emissions-reduction project and its associated rate rider if:

(1) the emissions-reduction project is needed to comply with new state or federal air quality standards; or

(2) the emissions-reduction project is required as a corrective action as part of any state or federal enforcement action.

(d) The commission may not include any costs of a proposed project in the emissions-reduction rider that are not directly allocable to reduction of emissions.

Subd. 6.Implementation.

Within 60 days of a final commission order, the public utility shall notify the commission and the Pollution Control Agency whether it will proceed with the project. Nothing in this section commits a public utility to implementing a proposed emissions-reduction project if the proposed project or terms of the emissions-reduction rider have been either modified or rejected by the commission. A public utility implementing a project under this section will not be required for a period of eight years after installation to undertake additional investments to comply with a new state requirement regarding pollutants addressed by the project at the project generating facility. This section does not affect requirements of federal law. The term of the rider shall extend for the period approved by the commission regardless of any subsequent state or federal requirement affecting any pollutant addressed by the approved emissions-reduction project and regardless of the sunset date in subdivision 8.

Subd. 7.Evaluation and report.

By January 15, 2005, the commission, in consultation with the commissioner of commerce and commissioner of the Pollution Control Agency, shall report to the legislature:

(1) the number of participating public utilities and qualifying projects proposed and approved under this section;

(2) the total cost of each project and any associated incentives;

(3) the reduction in air emissions achieved;

(4) rate impacts of the cost recovery mechanisms; and

(5) an assessment of the effectiveness of the cost recovery mechanism in accomplishing power plant emissions reductions in excess of those required by law.

Subd. 8.Sunset.

This section is effective until December 31, 2020, and applies to plans, projects, and riders approved before that date and modifications made to them after that date.

216B.1693 MS 2010 [Expired, 1Sp2003 c 11 art 2 s 4]

216B.1694 INNOVATIVE ENERGY PROJECT.

Subdivision 1.Definition.

For the purposes of this section, the term "innovative energy project" means a proposed energy-generation facility or group of facilities which may be located on up to three sites:

(1) that makes use of an innovative generation technology utilizing coal as a primary fuel in a highly efficient combined-cycle configuration with significantly reduced sulfur dioxide, nitrogen oxide, particulate, and mercury emissions from those of traditional technologies;

(2) that the project developer or owner certifies is a project capable of offering a long-term supply contract at a hedged, predictable cost; and

(3) that is designated by the commissioner of the Iron Range Resources and Rehabilitation Board as a project that is located in the taconite tax relief area on a site that has substantial real property with adequate infrastructure to support new or expanded development and that has received prior financial and other support from the board.

Subd. 2.Regulatory incentives.

(a) An innovative energy project:

(1) is exempted from the requirements for a certificate of need under section 216B.243, for the generation facilities, and transmission infrastructure associated with the generation facilities, but is subject to all applicable environmental review and permitting procedures of chapter 216E;

(2) once permitted and constructed, is eligible to increase the capacity of the associated transmission facilities without additional state review upon filing notice with the commission;

(3) has the power of eminent domain, which shall be limited to the sites and routes approved by the Environmental Quality Board for the project facilities. The project shall be considered a utility as defined in section 216E.01, subdivision 10, for the limited purpose of section 216E.12. The project shall report any intent to exercise eminent domain authority to the board;

(4) shall, prior to the approval by the commission of any arrangement to build or expand a fossil-fuel-fired generation facility, or to enter into an agreement to purchase capacity or energy from such a facility for a term exceeding five years, be considered as a supply option for the generation facility, and the commission shall ensure such consideration and take any action with respect to such supply proposal that it deems to be in the best interest of ratepayers;

(5) shall make a good faith effort to secure funding from the United States Department of Energy and the United States Department of Agriculture to conduct a demonstration project at the facility for either geologic or terrestrial carbon sequestration projects to achieve reductions in facility emissions or carbon dioxide;

(6) shall be entitled to enter into a contract with a public utility that owns a nuclear generation facility in the state to provide 450 megawatts of base-load capacity and energy under a long-term contract, subject to the approval of the terms and conditions of the contract by the commission. The commission may approve, disapprove, amend, or modify the contract in making its public interest determination, taking into consideration the project's economic development benefits to the state; the use of abundant domestic fuel sources; the stability of the price of the output from the project; the project's potential to contribute to a transition to hydrogen as a fuel resource; and the emissions reductions achieved compared to other solid fuel base-load technologies; and

(7) shall be eligible for a grant from the renewable development account, subject to the approval of the entity administering that account, of $2,000,000 a year for five years for development and engineering costs, including those costs related to mercury-removal technology; thermal efficiency optimization and emission minimization; environmental impact statement preparation and licensing; development of hydrogen production capabilities; and fuel cell development and utilization.

(b) This subdivision does not apply to nor affect a proposal to add utility-owned resources that is pending on May 29, 2003, before the Public Utilities Commission or to competitive bid solicitations to provide capacity or energy that is scheduled to be on line by December 31, 2006.

Subd. 3.Staging and permitting.

(a) A natural gas-fired plant that is located on one site designated as an innovative energy project site under subdivision 1, clause (3), is accorded the regulatory incentives granted to an innovative energy project under subdivision 2, clauses (1) to (3), and may exercise the authorities therein.

(b) Following issuance of a final state or federal environmental impact statement for an innovative energy project that was a subject of contested case proceedings before an administrative law judge:

(1) site and route permits and water appropriation approvals for an innovative energy project must also be deemed valid for a plant meeting the requirements of paragraph (a) and shall remain valid until the earlier of (i) four years from the date the final required state or federal preconstruction permit is issued or (ii) June 30, 2019; and

(2) no air, water, or other permit issued by a state agency that is necessary for constructing an innovative energy project may be the subject of contested case hearings, notwithstanding Minnesota Rules, parts 7000.1750 to 7000.2200.

216B.1695 ENVIRONMENTAL PROJECTS; ADVANCE DETERMINATION OF PRUDENCE.

Subdivision 1.Qualifying project.

A public utility may petition the commission for an advance determination of prudence for a project undertaken to comply with federal or state air quality standards of states in which the utility's electric generation facilities are located, if the project has an expected jurisdictional cost to Minnesota ratepayers of at least $10,000,000. A project is undertaken to comply with federal or state air quality standards if it is required:

(1) by the state in which the generation facility is located in a state implementation plan, permit, or order; or

(2) to comply with section 111 or 112 of the federal Clean Air Act, United States Code, title 42, section 7411 or 7412.

Subd. 2.Regulatory cost assessments and reports.

(a) A utility requesting an advance determination under subdivision 1 must, as part of the evidence required when filing a petition under subdivision 3, provide to the Public Utilities Commission and the Pollution Control Agency an assessment of all anticipated state and federal environmental regulations related to the production of electricity from the utility's facility subject to the filing, including regulations relating to:

(1) air pollution by nitrogen oxide and sulphur dioxide, including an assumption that Minnesota will be included in the federal Clean Air Interstate Rule region, hazardous air pollutants, carbon dioxide, particulates, and ozone;

(2) coal waste; and

(3) water consumption and water pollution.

(b) In addition, the utility shall provide an assessment of the financial and operational impacts of these pending regulations applicable to the generating facility that is the subject of the filing and provide a range of regulatory response scenarios that include, but are not limited to:

(1) the installation of pollution control equipment;

(2) the benefits of the retirement or repowering of the plant that is the subject of the filing with cleaner fuels considering the costs of complying with state and federal environmental regulations; and

(3) the use of pollution allowances to achieve compliance.

(c) The utility shall consult with interested stakeholders in establishing the scope of the regulatory, financial, and operational assessments prior to or during the 60-day period of the notice under subdivision 4.

Subd. 3.Petition.

A petition filed under this section must include a description of the project, evidence supporting the project's reasonableness, a discussion of project alternatives, a project implementation schedule, a cost estimate and support for the reasonableness of the estimated cost, and a description of the public utility's efforts to ensure the lowest reasonable costs. Following receipt of the Pollution Control Agency's verification under subdivision 4, the commission shall allow opportunity for oral and written comment on the petition. The commission shall make a final determination on the petition within ten months of its filing date. The commission must make findings in support of its determination.

Subd. 4.Verification.

At least 60 days prior to filing a petition to the commission under subdivision 3, the utility shall file notice with the Pollution Control Agency that describes the project and how it qualifies under subdivision 1. The Pollution Control Agency shall, within 60 days of receipt of the notice, verify that the project qualifies under subdivision 1, and shall forward written verification to the commission.

Subd. 5.Cost recovery.

The utility may begin recovery of costs that have been incurred by the utility in connection with implementation of the project in the next rate case following an advance determination of prudence or in a rider approved under section 216B.1692. The commission shall review the costs incurred by the utility for the project. The utility must show that the project costs are reasonable and necessary, and demonstrate its efforts to ensure the lowest reasonable project costs. Notwithstanding the commission's prior determination of prudence, it may accept, modify, or reject any of the project costs. The commission may determine whether to require an allowance for funds used during construction offset.

Subd. 5a.Rate of return.

The return on investment in the rider shall be at the level approved by the commission in the public utility's last general rate case, unless the commission determines that a different rate of return is in the public interest.

Subd. 6.Expiration.

A petition for an advance determination of prudence may not be filed after December 31, 2015.


COMPLAINTS AND HEARINGS

216B.17 COMPLAINT INVESTIGATION AND HEARING.

Subdivision 1.Investigation.

On its own motion or upon a complaint made against any public utility, by the governing body of any political subdivision, by another public utility, by the department, or by any 50 consumers of the particular utility that any of the rates, tolls, tariffs, charges, or schedules or any joint rate or any regulation, measurement, practice, act, or omission affecting or relating to the production, transmission, delivery, or furnishing of natural gas or electricity or any service in connection therewith is in any respect unreasonable, insufficient, or unjustly discriminatory, or that any service is inadequate or cannot be obtained, the commission shall proceed, with notice, to make such investigation as it may deem necessary. The commission may dismiss any complaint without a hearing if in its opinion a hearing is not in the public interest.

Subd. 2.Notice of complaint.

The commission shall, prior to any formal hearing, notify the public utility complained of that a complaint has been made, and ten days after the notice has been given the commission may proceed to set a time and place for a hearing and an investigation as provided in this section.

Subd. 3.Notice of hearing.

The commission shall give the public utility and the complainant ten days' notice of the time and place when and where the hearing will be held and the matters to be considered and determined. Both the public utility and complainant are entitled to be heard and to be represented by counsel. A hearing under this section is not a contested case under chapter 14.

Subd. 4.Notice to local governments and interested persons.

Notice shall also be given to the governing bodies of affected municipalities and counties, and to any other persons the commission shall deem necessary.

Subd. 5.Combined notice.

The notice provided for in subdivisions 2 and 3 may be combined but if combined the notice shall not be less than ten days.

Subd. 6.Complaint petition.

The commission shall have the power to hear, determine, and adjust complaints made against any municipally owned gas or electric utility with respect to rates and services upon petition of ten percent of the nonresident consumers of the municipally owned utility or 25 such nonresident consumers whichever is less. The hearing of the complaints shall be governed by this section.

Subd. 6a.Cooperative electric associations.

For the purposes of this section, public utility shall include cooperative electric associations with respect to service standards and practices only.

Subd. 7.Evidence.

Section 14.60 shall be applicable to all contested cases before the commission.

Subd. 8.Further action by commission.

If after making an investigation under subdivision 1 and holding a hearing under this section, the commission finds that all significant factual issues raised have not been resolved to its satisfaction:

(1) for investigations concerning the reasonableness of rates of a public utility, if the commission is unable to resolve the complaint with the utility, the commission may order the utility to initiate a rate proceeding under section 216B.16, provided, however, that the utility must be allowed at least 120 days after the date of the commission's order to initiate the proceeding; and

(2) for investigations of other matters, the commission shall order that a contested case proceeding be conducted under chapter 14.

216B.18 SERVICE OF NOTICE.

Service of notice of all hearings, investigations, and proceedings pending before the commission and of complaints, reports, orders, and other documents must be made personally, by electronic service as provided in section 216.17, or by mail as the commission may direct. Regulated utilities and state agencies must provide an electronic address to the commission for electronic service purposes and agree to accept electronic service as official service.

216B.19 JOINT HEARING AND INVESTIGATION.

In the discharge of its duties under Laws 1974, chapter 429, the commission or the department may cooperate with similar commissions of other states and any federal agency and may hold joint hearings and make joint investigations with other commissions.

216B.20 SEPARATE RATE HEARING.

The commission may, in its discretion, when complaint is made of more than one rate or charge, order separate hearings thereon, and may consider and determine the several matters complained of separately and at times it may prescribe.

History:

1974 c 429 s 20

216B.21 SUMMARY INVESTIGATION.

Subdivision 1.Authority.

Whenever the commission has reason to believe that any rate or charge may be unreasonable or unjustly discriminatory or that any service is inadequate or cannot be obtained or that an investigation of any matter relating to any public utility should for any reason be made, it may on its own motion summarily investigate the same with or without notice.

Subd. 2.Formal hearing.

If, after making the summary investigation, the commission becomes satisfied that sufficient grounds exist to warrant a formal hearing being ordered as to the matters investigated, it shall set a time and place for a hearing.

Subd. 3.Notice.

Notice of the time and place for the hearing shall be made as provided in sections 216B.17 and 216B.18.

History:

1974 c 429 s 21

216B.22 MUNICIPALITY; AMICUS CURIAE AUTHORITY.

Any municipality that regulates and controls the exercise of a public utility franchise by reason of its home rule charter on January 1, 1975, is authorized to assist the Public Utilities Commission as amicus curiae in any proceeding brought before the commission with respect to the rates, fares, prices, regulation, or control of any utility operating therein.

216B.23 LAWFUL RATE; REASONABLE SERVICE.

Subdivision 1.Determination as to rate; order.

Whenever upon an investigation made under the provisions of Laws 1974, chapter 429, the commission shall find rates, tolls, charges, schedules or joint rates to be unjust, unreasonable, insufficient, or unjustly discriminatory or preferential or otherwise unreasonable or unlawful, the commission shall determine and by order fix reasonable rates, tolls, charges, schedules, or joint rates to be imposed, observed, and followed in the future in lieu of those found to be unreasonable or unlawful.

Subd. 1a.Authority to issue refund.

(a) On determining that a public utility has charged a rate in violation of this chapter, a commission rule, or a commission order, the commission, after conducting a proceeding, may require the public utility to refund to its customers, in a manner approved by the commission, any revenues the commission finds were collected as a result of the unlawful conduct. Any refund authorized by this section is permitted in addition to any remedies authorized by section 216B.16 or any other law governing rates. Exercising authority under this section does not preclude the commission from pursuing penalties under sections 216B.57 to 216B.61 for the same conduct.

(b) This section must not be construed as allowing:

(1) retroactive ratemaking;

(2) refunds based on claims that prior or current approved rates have been unjust, unreasonable, unreasonably preferential, discriminatory, insufficient, inequitable, or inconsistent in application to a class of customers; or

(3) refunds based on claims that approved rates have not encouraged energy conservation or renewable energy use, or have not furthered the goals of section 216B.164, 216B.241, or 216C.05.

(c) A refund under this subdivision does not apply to revenues collected more than six years before the date of the notice of the commission proceeding required under this subdivision.

Subd. 2.Finding as to service; order.

Whenever the commission shall find any regulations, measurements, practices, acts, or service to be unjust, unreasonable, insufficient, preferential, unjustly discriminatory, or otherwise unreasonable or unlawful, or shall find that any service which can be reasonably demanded cannot be obtained, the commission shall determine and by order fix reasonable measurements, regulations, acts, practices, or service to be furnished, imposed, observed and followed in the future in lieu of those found to be unreasonable, inadequate, or otherwise unlawful, and shall make any other order respecting the measurement, regulation, act, practice, or service as shall be just and reasonable.

Subd. 3.Copy of order served; notice.

A copy of the order shall be served upon the person against whom it runs or the person's attorney, and notice thereof shall be given to the other parties to the proceedings or their attorneys.

History:

1974 c 429 s 23; 1986 c 444; 2009 c 110 s 14


ENERGY CONSERVATION; UTILITY CONSTRUCTION

216B.24 CONSTRUCTION OF MAJOR FACILITY; FILING PLANS.

Subdivision 1.Major utility facility defined.

The words "major utility facility" means: (1) electric generating plant and associated facilities designed for, or capable of, operation at a capacity of 50 megawatts or more; (2) an electric transmission line and associated facilities of a design capacity of 125 kilovolts or more; and (3) a gas transmission line and associated facilities designed for, or capable of, transporting gas at pressures in excess of 125 pounds per square inch; provided, however, that the words "major utility facility" shall not include electric or gas distribution lines and gas gathering lines and associated facilities as defined by the commission.

Subd. 2.Construction plan filed; rules.

Under rules as the commission may prescribe, every public utility shall file with the commission, within the time and in the form as the commission may designate, plans showing any contemplated construction of major utility facilities.

Subd. 3.Applicability to municipalities.

The provisions of this section shall apply to the construction of major utility facilities by a municipally owned gas or electric utility.

216B.2401 ENERGY SAVINGS POLICY GOAL.

The legislature finds that energy savings are an energy resource, and that cost-effective energy savings are preferred over all other energy resources. The legislature further finds that cost-effective energy savings should be procured systematically and aggressively in order to reduce utility costs for businesses and residents, improve the competitiveness and profitability of businesses, create more energy-related jobs, reduce the economic burden of fuel imports, and reduce pollution and emissions that cause climate change. Therefore, it is the energy policy of the state of Minnesota to achieve annual energy savings equal to at least 1.5 percent of annual retail energy sales of electricity and natural gas through cost-effective energy conservation improvement programs and rate design, energy efficiency achieved by energy consumers without direct utility involvement, energy codes and appliance standards, programs designed to transform the market or change consumer behavior, energy savings resulting from efficiency improvements to the utility infrastructure and system, and other efforts to promote energy efficiency and energy conservation.

216B.241 ENERGY CONSERVATION IMPROVEMENT.

Subdivision 1.Definitions.

For purposes of this section and section 216B.16, subdivision 6b, the terms defined in this subdivision have the meanings given them.

(a) "Commission" means the Public Utilities Commission.

(b) "Commissioner" means the commissioner of commerce.

(c) "Department" means the Department of Commerce.

(d) "Energy conservation" means demand-side management of energy supplies resulting in a net reduction in energy use. Load management that reduces overall energy use is energy conservation.

(e) "Energy conservation improvement" means a project that results in energy efficiency or energy conservation. Energy conservation improvement may include waste heat that is recovered and converted into electricity, but does not include electric utility infrastructure projects approved by the commission under section 216B.1636. Energy conservation improvement also includes waste heat recovered and used as thermal energy.

(f) "Energy efficiency" means measures or programs, including energy conservation measures or programs, that target consumer behavior, equipment, processes, or devices designed to produce either an absolute decrease in consumption of electric energy or natural gas or a decrease in consumption of electric energy or natural gas on a per unit of production basis without a reduction in the quality or level of service provided to the energy consumer.

(g) "Gross annual retail energy sales" means annual electric sales to all retail customers in a utility's or association's Minnesota service territory or natural gas throughput to all retail customers, including natural gas transportation customers, on a utility's distribution system in Minnesota. For purposes of this section, gross annual retail energy sales exclude:

(1) gas sales to:

(i) a large energy facility;

(ii) a large customer facility whose natural gas utility has been exempted by the commissioner under subdivision 1a, paragraph (b), with respect to natural gas sales made to the large customer facility; and

(iii) a commercial gas customer facility whose natural gas utility has been exempted by the commissioner under subdivision 1a, paragraph (c), with respect to natural gas sales made to the commercial gas customer facility; and

(2) electric sales to a large customer facility whose electric utility has been exempted by the commissioner under subdivision 1a, paragraph (b), with respect to electric sales made to the large customer facility.

(h) "Investments and expenses of a public utility" includes the investments and expenses incurred by a public utility in connection with an energy conservation improvement, including but not limited to:

(1) the differential in interest cost between the market rate and the rate charged on a no-interest or below-market interest loan made by a public utility to a customer for the purchase or installation of an energy conservation improvement;

(2) the difference between the utility's cost of purchase or installation of energy conservation improvements and any price charged by a public utility to a customer for such improvements.

(i) "Large customer facility" means all buildings, structures, equipment, and installations at a single site that collectively (1) impose a peak electrical demand on an electric utility's system of not less than 20,000 kilowatts, measured in the same way as the utility that serves the customer facility measures electrical demand for billing purposes or (2) consume not less than 500 million cubic feet of natural gas annually. In calculating peak electrical demand, a large customer facility may include demand offset by on-site cogeneration facilities and, if engaged in mineral extraction, may aggregate peak energy demand from the large customer facility's mining and processing operations.

(j) "Large energy facility" has the meaning given it in section 216B.2421, subdivision 2, clause (1).

(k) "Load management" means an activity, service, or technology to change the timing or the efficiency of a customer's use of energy that allows a utility or a customer to respond to wholesale market fluctuations or to reduce peak demand for energy or capacity.

(l) "Low-income programs" means energy conservation improvement programs that directly serve the needs of low-income persons, including low-income renters.

(m) "Qualifying utility" means a utility that supplies the energy to a customer that enables the customer to qualify as a large customer facility.

(n) "Waste heat recovered and used as thermal energy" means capturing heat energy that would otherwise be exhausted or dissipated to the environment from machinery, buildings, or industrial processes and productively using such recovered thermal energy where it was captured or distributing it as thermal energy to other locations where it is used to reduce demand-side consumption of natural gas, electric energy, or both.

(o) "Waste heat recovery converted into electricity" means an energy recovery process that converts otherwise lost energy from the heat of exhaust stacks or pipes used for engines or manufacturing or industrial processes, or the reduction of high pressure in water or gas pipelines.

Subd. 1a.Investment, expenditure, and contribution; public utility.

(a) For purposes of this subdivision and subdivision 2, "public utility" has the meaning given it in section 216B.02, subdivision 4. Each public utility shall spend and invest for energy conservation improvements under this subdivision and subdivision 2 the following amounts:

(1) for a utility that furnishes gas service, 0.5 percent of its gross operating revenues from service provided in the state;

(2) for a utility that furnishes electric service, 1.5 percent of its gross operating revenues from service provided in the state; and

(3) for a utility that furnishes electric service and that operates a nuclear-powered electric generating plant within the state, two percent of its gross operating revenues from service provided in the state.

For purposes of this paragraph (a), "gross operating revenues" do not include revenues from large customer facilities exempted under paragraph (b), or from commercial gas customers that are exempted under paragraph (c) or (e).

(b) The owner of a large customer facility may petition the commissioner to exempt both electric and gas utilities serving the large customer facility from the investment and expenditure requirements of paragraph (a) with respect to retail revenues attributable to the large customer facility. The filing must include a discussion of the competitive or economic pressures facing the owner of the facility and the efforts taken by the owner to identify, evaluate, and implement energy conservation and efficiency improvements. A filing submitted on or before October 1 of any year must be approved within 90 days and become effective January 1 of the year following the filing, unless the commissioner finds that the owner of the large customer facility has failed to take reasonable measures to identify, evaluate, and implement energy conservation and efficiency improvements. If a facility qualifies as a large customer facility solely due to its peak electrical demand or annual natural gas usage, the exemption may be limited to the qualifying utility if the commissioner finds that the owner of the large customer facility has failed to take reasonable measures to identify, evaluate, and implement energy conservation and efficiency improvements with respect to the nonqualifying utility. Once an exemption is approved, the commissioner may request the owner of a large customer facility to submit, not more often than once every five years, a report demonstrating the large customer facility's ongoing commitment to energy conservation and efficiency improvement after the exemption filing. The commissioner may request such reports for up to ten years after the effective date of the exemption, unless the majority ownership of the large customer facility changes, in which case the commissioner may request additional reports for up to ten years after the change in ownership occurs. The commissioner may, within 180 days of receiving a report submitted under this paragraph, rescind any exemption granted under this paragraph upon a determination that the large customer facility is not continuing to make reasonable efforts to identify, evaluate, and implement energy conservation improvements. A large customer facility that is, under an order from the commissioner, exempt from the investment and expenditure requirements of paragraph (a) as of December 31, 2010, is not required to submit a report to retain its exempt status, except as otherwise provided in this paragraph with respect to ownership changes. No exempt large customer facility may participate in a utility conservation improvement program unless the owner of the facility submits a filing with the commissioner to withdraw its exemption.

(c) A commercial gas customer that is not a large customer facility and that purchases or acquires natural gas from a public utility having fewer than 600,000 natural gas customers in Minnesota may petition the commissioner to exempt gas utilities serving the commercial gas customer from the investment and expenditure requirements of paragraph (a) with respect to retail revenues attributable to the commercial gas customer. The petition must be supported by evidence demonstrating that the commercial gas customer has acquired or can reasonably acquire the capability to bypass use of the utility's gas distribution system by obtaining natural gas directly from a supplier not regulated by the commission. The commissioner shall grant the exemption if the commissioner finds that the petitioner has made the demonstration required by this paragraph.

(d) The commissioner may require investments or spending greater than the amounts required under this subdivision for a public utility whose most recent advance forecast required under section 216B.2422 or 216C.17 projects a peak demand deficit of 100 megawatts or greater within five years under midrange forecast assumptions.

(e) A public utility or owner of a large customer facility may appeal a decision of the commissioner under paragraph (b), (c), or (d) to the commission under subdivision 2. In reviewing a decision of the commissioner under paragraph (b), (c), or (d), the commission shall rescind the decision if it finds that the required investments or spending will:

(1) not result in cost-effective energy conservation improvements; or

(2) otherwise not be in the public interest.

Subd. 1b.Conservation improvement by cooperative association or municipality.

(a) This subdivision applies to:

(1) a cooperative electric association that provides retail service to its members;

(2) a municipality that provides electric service to retail customers; and

(3) a municipality with more than 1,000,000,000 cubic feet in annual throughput sales to natural gas to retail customers.

(b) Each cooperative electric association and municipality subject to this subdivision shall spend and invest for energy conservation improvements under this subdivision the following amounts:

(1) for a municipality, 0.5 percent of its gross operating revenues from the sale of gas and 1.5 percent of its gross operating revenues from the sale of electricity, excluding gross operating revenues from electric and gas service provided in the state to large electric customer facilities; and

(2) for a cooperative electric association, 1.5 percent of its gross operating revenues from service provided in the state, excluding gross operating revenues from service provided in the state to large electric customer facilities indirectly through a distribution cooperative electric association.

(c) Each municipality and cooperative electric association subject to this subdivision shall identify and implement energy conservation improvement spending and investments that are appropriate for the municipality or association, except that a municipality or association may not spend or invest for energy conservation improvements that directly benefit a large energy facility or a large electric customer facility for which the commissioner has issued an exemption under subdivision 1a, paragraph (b).

(d) Each municipality and cooperative electric association subject to this subdivision may spend and invest annually up to ten percent of the total amount required to be spent and invested on energy conservation improvements under this subdivision on research and development projects that meet the definition of energy conservation improvement in subdivision 1 and that are funded directly by the municipality or cooperative electric association.

(e) Load-management activities may be used to meet 50 percent of the conservation investment and spending requirements of this subdivision.

(f) A generation and transmission cooperative electric association that provides energy services to cooperative electric associations that provide electric service at retail to consumers may invest in energy conservation improvements on behalf of the associations it serves and may fulfill the conservation, spending, reporting, and energy-savings goals on an aggregate basis. A municipal power agency or other not-for-profit entity that provides energy service to municipal utilities that provide electric service at retail may invest in energy conservation improvements on behalf of the municipal utilities it serves and may fulfill the conservation, spending, reporting, and energy-savings goals on an aggregate basis, under an agreement between the municipal power agency or not-for-profit entity and each municipal utility for funding the investments.

(g) Each municipality or cooperative shall file energy conservation improvement plans by June 1 on a schedule determined by order of the commissioner, but at least every three years. Plans received by June 1 must be approved or approved as modified by the commissioner by December 1 of the same year. The municipality or cooperative shall provide an evaluation to the commissioner detailing its energy conservation improvement spending and investments for the previous period. The evaluation must briefly describe each conservation program and must specify the energy savings or increased efficiency in the use of energy within the service territory of the utility or association that is the result of the spending and investments. The evaluation must analyze the cost-effectiveness of the utility's or association's conservation programs, using a list of baseline energy and capacity savings assumptions developed in consultation with the department. The commissioner shall review each evaluation and make recommendations, where appropriate, to the municipality or association to increase the effectiveness of conservation improvement activities.

(h) MS 2010 [Expired, 1Sp2003 c 11 art 3 s 4; 2007 c 136 art 2 s 5]

(i) The commissioner shall consider and may require a utility, association, or other entity providing energy efficiency and conservation services under this section to undertake a program suggested by an outside source, including a political subdivision, nonprofit corporation, or community organization.

Subd. 1c.Energy-saving goals.

(a) The commissioner shall establish energy-saving goals for energy conservation improvement expenditures and shall evaluate an energy conservation improvement program on how well it meets the goals set.

(b) Each individual utility and association shall have an annual energy-savings goal equivalent to 1.5 percent of gross annual retail energy sales unless modified by the commissioner under paragraph (d). The savings goals must be calculated based on the most recent three-year weather-normalized average. A utility or association may elect to carry forward energy savings in excess of 1.5 percent for a year to the succeeding three calendar years, except that savings from electric utility infrastructure projects allowed under paragraph (d) may be carried forward for five years. A particular energy savings can be used only for one year's goal.

(c) The commissioner must adopt a filing schedule that is designed to have all utilities and associations operating under an energy-savings plan by calendar year 2010.

(d) In its energy conservation improvement plan filing, a utility or association may request the commissioner to adjust its annual energy-savings percentage goal based on its historical conservation investment experience, customer class makeup, load growth, a conservation potential study, or other factors the commissioner determines warrants an adjustment. The commissioner may not approve a plan of a public utility that provides for an annual energy-savings goal of less than one percent of gross annual retail energy sales from energy conservation improvements.

A utility or association may include in its energy conservation plan energy savings from electric utility infrastructure projects approved by the commission under section 216B.1636 or waste heat recovery converted into electricity projects that may count as energy savings in addition to a minimum energy-savings goal of at least one percent for energy conservation improvements. Electric utility infrastructure projects must result in increased energy efficiency greater than that which would have occurred through normal maintenance activity.

(e) An energy-savings goal is not satisfied by attaining the revenue expenditure requirements of subdivisions 1a and 1b, but can only be satisfied by meeting the energy-savings goal established in this subdivision.

(f) An association or utility is not required to make energy conservation investments to attain the energy-savings goals of this subdivision that are not cost-effective even if the investment is necessary to attain the energy-savings goals. For the purpose of this paragraph, in determining cost-effectiveness, the commissioner shall consider the costs and benefits to ratepayers, the utility, participants, and society. In addition, the commissioner shall consider the rate at which an association or municipal utility is increasing its energy savings and its expenditures on energy conservation.

(g) On an annual basis, the commissioner shall produce and make publicly available a report on the annual energy savings and estimated carbon dioxide reductions achieved by the energy conservation improvement programs for the two most recent years for which data is available. The commissioner shall report on program performance both in the aggregate and for each entity filing an energy conservation improvement plan for approval or review by the commissioner.

(h) By January 15, 2010, the commissioner shall report to the legislature whether the spending requirements under subdivisions 1a and 1b are necessary to achieve the energy-savings goals established in this subdivision.

Subd. 1d. Technical assistance.

The commissioner shall evaluate energy conservation improvement programs on the basis of cost-effectiveness and the reliability of the technologies employed. The commissioner shall, by order, establish, maintain, and update energy-savings assumptions that must be used when filing energy conservation improvement programs. The commissioner shall establish an inventory of the most effective energy conservation programs, techniques, and technologies, and encourage all Minnesota utilities to implement them, where appropriate, in their service territories. The commissioner shall describe these programs in sufficient detail to provide a utility reasonable guidance concerning implementation. The commissioner shall prioritize the opportunities in order of potential energy savings and in order of cost-effectiveness. The commissioner may contract with a third party to carry out any of the commissioner's duties under this subdivision, and to obtain technical assistance to evaluate the effectiveness of any conservation improvement program. The commissioner may assess up to $800,000 annually until June 30, 2009, and $450,000 annually thereafter for the purposes of this subdivision. The assessments must be deposited in the state treasury and credited to the energy and conservation account created under subdivision 2a. An assessment made under this subdivision is not subject to the cap on assessments provided by section 216B.62, or any other law.

Subd. 1e.Applied research and development grants.

(a) The commissioner may, by order, approve and make grants for applied research and development projects of general applicability that identify new technologies or strategies to maximize energy savings, improve the effectiveness of energy conservation programs, or document the carbon dioxide reductions from energy conservation programs. When approving projects, the commissioner shall consider proposals and comments from utilities and other interested parties. The commissioner may assess up to $3,600,000 annually for the purposes of this subdivision. The assessments must be deposited in the state treasury and credited to the energy and conservation account created under subdivision 2a. An assessment made under this subdivision is not subject to the cap on assessments provided by section 216B.62, or any other law.

(b) The commissioner, as part of the assessment authorized under paragraph (a), shall annually assess and grant up to $500,000 for the purpose of subdivision 9.

(c) The commissioner, as part of the assessment authorized under paragraph (a), each state fiscal year shall assess $500,000 for a grant to the partnership created by section 216C.385, subdivision 2. The grant must be used to exercise the powers and perform the duties specified in section 216C.385, subdivision 3.

(d) By February 15 annually, the commissioner shall report to the chairs and ranking minority members of the committees of the legislature with primary jurisdiction over energy policy and energy finance on the assessments made under this subdivision for the previous calendar year and the use of the assessment. The report must clearly describe the activities supported by the assessment and the parties that engaged in those activities.

Subd. 1f.Facilities energy efficiency.

(a) The commissioner of administration and the commissioner of commerce shall maintain and, as needed, revise the sustainable building design guidelines developed under section 16B.325.

(b) The commissioner of administration and the commissioner of commerce shall maintain and update the benchmarking tool developed under Laws 2001, chapter 212, article 1, section 3, so that all public buildings can use the benchmarking tool to maintain energy use information for the purposes of establishing energy efficiency benchmarks, tracking building performance, and measuring the results of energy efficiency and conservation improvements.

(c) The commissioner shall require that utilities include in their conservation improvement plans programs that facilitate professional engineering verification to qualify a building as Energy Star-labeled, Leadership in Energy and Environmental Design (LEED) certified, or Green Globes-certified. The state goal is to achieve certification of 1,000 commercial buildings as Energy Star-labeled, and 100 commercial buildings as LEED-certified or Green Globes-certified by December 31, 2010.

(d) The commissioner may assess up to $500,000 annually for the purposes of this subdivision. The assessments must be deposited in the state treasury and credited to the energy and conservation account created under subdivision 2a. An assessment made under this subdivision is not subject to the cap on assessments provided by section 216B.62, or any other law.

Subd. 1g.Manner of filing and service.

(a) A public utility, generation and transmission cooperative electric association, municipal power agency, cooperative electric association, and municipal utility shall submit filings to the department via the department's electronic filing system. The commissioner may approve an exemption from this requirement in the event an affected utility or association is unable to submit filings via the department's electronic filing system. All other interested parties shall submit filings to the department via the department's electronic filing system whenever practicable but may also file by personal delivery or by mail.

(b) Submission of a document to the department's electronic filing system constitutes service on the department. Where department rule requires service of a notice, order, or other document by the department, utility, association, or interested party upon persons on a service list maintained by the department, service may be made by personal delivery, mail, or electronic service, except that electronic service may only be made upon persons on the service list who have previously agreed in writing to accept electronic service at an electronic address provided to the department for electronic service purposes.

Subd. 2.Programs.

(a) The commissioner may require public utilities to make investments and expenditures in energy conservation improvements, explicitly setting forth the interest rates, prices, and terms under which the improvements must be offered to the customers. The required programs must cover no more than a three-year period. Public utilities shall file conservation improvement plans by June 1, on a schedule determined by order of the commissioner, but at least every three years. Plans received by a public utility by June 1 must be approved or approved as modified by the commissioner by December 1 of that same year. The commissioner shall evaluate the program on the basis of cost-effectiveness and the reliability of technologies employed. The commissioner's order must provide to the extent practicable for a free choice, by consumers participating in the program, of the device, method, material, or project constituting the energy conservation improvement and for a free choice of the seller, installer, or contractor of the energy conservation improvement, provided that the device, method, material, or project seller, installer, or contractor is duly licensed, certified, approved, or qualified, including under the residential conservation services program, where applicable.

(b) The commissioner may require a utility to make an energy conservation improvement investment or expenditure whenever the commissioner finds that the improvement will result in energy savings at a total cost to the utility less than the cost to the utility to produce or purchase an equivalent amount of new supply of energy. The commissioner shall nevertheless ensure that every public utility operate one or more programs under periodic review by the department.

(c) Each public utility subject to subdivision 1a may spend and invest annually up to ten percent of the total amount required to be spent and invested on energy conservation improvements under this section by the utility on research and development projects that meet the definition of energy conservation improvement in subdivision 1 and that are funded directly by the public utility.

(d) A public utility may not spend for or invest in energy conservation improvements that directly benefit a large energy facility or a large electric customer facility for which the commissioner has issued an exemption pursuant to subdivision 1a, paragraph (b). The commissioner shall consider and may require a utility to undertake a program suggested by an outside source, including a political subdivision, a nonprofit corporation, or community organization.

(e) A utility, a political subdivision, or a nonprofit or community organization that has suggested a program, the attorney general acting on behalf of consumers and small business interests, or a utility customer that has suggested a program and is not represented by the attorney general under section 8.33 may petition the commission to modify or revoke a department decision under this section, and the commission may do so if it determines that the program is not cost-effective, does not adequately address the residential conservation improvement needs of low-income persons, has a long-range negative effect on one or more classes of customers, or is otherwise not in the public interest. The commission shall reject a petition that, on its face, fails to make a reasonable argument that a program is not in the public interest.

(f) The commissioner may order a public utility to include, with the filing of the utility's annual status report, the results of an independent audit of the utility's conservation improvement programs and expenditures performed by the department or an auditor with experience in the provision of energy conservation and energy efficiency services approved by the commissioner and chosen by the utility. The audit must specify the energy savings or increased efficiency in the use of energy within the service territory of the utility that is the result of the spending and investments. The audit must evaluate the cost-effectiveness of the utility's conservation programs.

(g) A gas utility may not spend for or invest in energy conservation improvements that directly benefit a large customer facility or commercial gas customer facility for which the commissioner has issued an exemption pursuant to subdivision 1a, paragraph (b), (c), or (e). The commissioner shall consider and may require a utility to undertake a program suggested by an outside source, including a political subdivision, a nonprofit corporation, or a community organization.

Subd. 2a.Energy and conservation account.

The energy and conservation account is established in the special revenue fund in the state treasury. The commissioner must deposit money assessed or contributed under subdivisions 1d, 1e, 1f, and 7 in the state treasury and credit it to the energy and conservation account in the special revenue fund. Money in the account is appropriated to the commissioner for the purposes of subdivisions 1d, 1e, 1f, and 7. Interest on money in the account accrues to the account.

Subd. 2b.Recovery of expenses.

The commission shall allow a utility to recover expenses resulting from a conservation improvement program required by the department and contributions and assessments to the energy and conservation account, unless the recovery would be inconsistent with a financial incentive proposal approved by the commission. The commission shall allow a cooperative electric association subject to rate regulation under section 216B.026, to recover expenses resulting from energy conservation improvement programs, load management programs, and assessments and contributions to the energy and conservation account unless the recovery would be inconsistent with a financial incentive proposal approved by the commission. In addition, a utility may file annually, or the Public Utilities Commission may require the utility to file, and the commission may approve, rate schedules containing provisions for the automatic adjustment of charges for utility service in direct relation to changes in the expenses of the utility for real and personal property taxes, fees, and permits, the amounts of which the utility cannot control. A public utility is eligible to file for adjustment for real and personal property taxes, fees, and permits under this subdivision only if, in the year previous to the year in which it files for adjustment, it has spent or invested at least 1.75 percent of its gross revenues from provision of electric service, excluding gross operating revenues from electric service provided in the state to large electric customer facilities for which the commissioner has issued an exemption under subdivision 1a, paragraph (b), and 0.6 percent of its gross revenues from provision of gas service, excluding gross operating revenues from gas services provided in the state to large electric customer facilities for which the commissioner has issued an exemption under subdivision 1a, paragraph (b), for that year for energy conservation improvements under this section.

Subd. 2c.Performance incentives.

By December 31, 2008, the commission shall review any incentive plan for energy conservation improvement it has approved under section 216B.16, subdivision 6c, and adjust the utility performance incentives to recognize making progress toward and meeting the energy-savings goals established in subdivision 1c.

Subd. 3.Ownership of energy conservation improvement.

An energy conservation improvement made to or installed in a building in accordance with this section, except systems owned by the utility and designed to turn off, limit, or vary the delivery of energy, are the exclusive property of the owner of the building except to the extent that the improvement is subjected to a security interest in favor of the utility in case of a loan to the building owner. The utility has no liability for loss, damage or injury caused directly or indirectly by an energy conservation improvement except for negligence by the utility in purchase, installation, or modification of the product.

Subd. 4.Federal law prohibitions.

If investments by public utilities in energy conservation improvements are in any manner prohibited or restricted by federal law and there is a provision under which the prohibition or restriction may be waived, then the commission, the governor, or any other necessary state agency or officer shall take all necessary and appropriate steps to secure a waiver with respect to those public utility investments in energy conservation improvements included in this section.

Subd. 5.Efficient lighting program.

(a) Each public utility, cooperative electric association, and municipal utility that provides electric service to retail customers shall include as part of its conservation improvement activities a program to strongly encourage the use of fluorescent and high-intensity discharge lamps. The program must include at least a public information campaign to encourage use of the lamps and proper management of spent lamps by all customer classifications.

(b) A public utility that provides electric service at retail to 200,000 or more customers shall establish, either directly or through contracts with other persons, including lamp manufacturers, distributors, wholesalers, and retailers and local government units, a system to collect for delivery to a reclamation or recycling facility spent fluorescent and high-intensity discharge lamps from households and from small businesses as defined in section 645.445 that generate an average of fewer than ten spent lamps per year.

(c) A collection system must include establishing reasonably convenient locations for collecting spent lamps from households and financial incentives sufficient to encourage spent lamp generators to take the lamps to the collection locations. Financial incentives may include coupons for purchase of new fluorescent or high-intensity discharge lamps, a cash back system, or any other financial incentive or group of incentives designed to collect the maximum number of spent lamps from households and small businesses that is reasonably feasible.

(d) A public utility that provides electric service at retail to fewer than 200,000 customers, a cooperative electric association, or a municipal utility that provides electric service at retail to customers may establish a collection system under paragraphs (b) and (c) as part of conservation improvement activities required under this section.

(e) The commissioner of the Pollution Control Agency may not, unless clearly required by federal law, require a public utility, cooperative electric association, or municipality that establishes a household fluorescent and high-intensity discharge lamp collection system under this section to manage the lamps as hazardous waste as long as the lamps are managed to avoid breakage and are delivered to a recycling or reclamation facility that removes mercury and other toxic materials contained in the lamps prior to placement of the lamps in solid waste.

(f) If a public utility, cooperative electric association, or municipal utility contracts with a local government unit to provide a collection system under this subdivision, the contract must provide for payment to the local government unit of all the unit's incremental costs of collecting and managing spent lamps.

(g) All the costs incurred by a public utility, cooperative electric association, or municipal utility for promotion and collection of fluorescent and high-intensity discharge lamps under this subdivision are conservation improvement spending under this section.

Subd. 5a.Qualifying solar energy project.

(a) A utility or association may include in its conservation plan programs for the installation of qualifying solar energy projects as defined by section 216B.2411 to the extent of the spending allowed for generation projects by section 216B.2411. The cost-effectiveness of a qualifying solar energy project may be determined by a different standard than for other energy conservation improvements under this section if the commissioner determines it is in the public interest to do so to encourage solar energy projects. Energy savings from qualifying solar energy projects may not be counted toward the minimum energy-savings goal of at least one percent for energy conservation improvements required under subdivision 1c, but may, if the conservation plan is approved:

(1) be counted toward energy savings above that minimum percentage; and

(2) be eligible for a performance incentive under section 216B.16, subdivision 6c, or 216B.241, subdivision 2c, that is distinct from the incentive for energy conservation and is based on the competitiveness and cost-effectiveness of solar projects in relation to other potential solar projects available to the utility.

(b) Qualifying solar energy projects may not be considered when establishing demand-side management targets under section 216B.2422, 216B.243, or any other section of this chapter.

Subd. 5b.Biomethane purchases.

(a) A natural gas utility may include in its conservation plan purchases of biomethane, and may use up to five percent of the total amount to be spent on energy conservation improvements under this section for that purpose. The cost-effectiveness of biomethane purchases may be determined by a different standard than for other energy conservation improvements under this section if the commissioner determines that doing so is in the public interest in order to encourage biomethane purchases. Energy savings from purchasing biomethane may not be counted toward the minimum energy-savings goal of at least one percent for energy conservation improvements required under subdivision 1c, but may, if the conservation plan is approved:

(1) be counted toward energy savings above that minimum percentage; and

(2) be considered when establishing performance incentives under subdivision 2c.

(b) For the purposes of this subdivision, "biomethane" means biogas produced through anaerobic digestion of biomass, gasification of biomass, or other effective conversion processes, that is cleaned and purified into biomethane that meets natural gas utility quality specifications for use in a natural gas utility distribution system.

Subd. 5c.Large solar electric generating plant.

(a) For the purpose of this subdivision:

(1) "project" means a solar electric generation project consisting of arrays of solar photovoltaic cells with a capacity of up to two megawatts located on the site of a closed landfill in Olmsted County owned by the Minnesota Pollution Control Agency; and

(2) "cooperative electric association" means a generation and transmission cooperative electric association that has a member distribution cooperative association to which it provides wholesale electric service in whose service territory a project is located.

(b) A cooperative electric association may elect to count all of its purchases of electric energy from a project toward only one of the following:

(1) its energy-savings goal under subdivision 1c; or

(2) its energy objective or standard under section 216B.1691.

(c) A cooperative electric association may include in its conservation plan purchases of electric energy from a project. The cost-effectiveness of project purchases may be determined by a different standard than for other energy conservation improvements under this section if the commissioner determines that doing so is in the public interest in order to encourage solar energy. The kilowatt hours of solar energy purchased by a cooperative electric association from a project may count for up to 33 percent of its one percent savings goal under subdivision 1c or up to 22 percent of its 1.5 percent savings goal under that subdivision. Expenditures made by a cooperative association for the purchase of energy from a project may not be used to meet the revenue expenditure requirements of subdivisions 1a and 1b.

Subd. 6.

MS 2008 [Expired]

Subd. 7.Low-income programs.

(a) The commissioner shall ensure that each utility and association provides low-income programs. When approving spending and energy-savings goals for low-income programs, the commissioner shall consider historic spending and participation levels, energy savings for low-income programs, and the number of low-income persons residing in the utility's service territory. A municipal utility that furnishes gas service must spend at least 0.2 percent, and a public utility furnishing gas service must spend at least 0.4 percent, of its most recent three-year average gross operating revenue from residential customers in the state on low-income programs. A utility or association that furnishes electric service must spend at least 0.1 percent of its gross operating revenue from residential customers in the state on low-income programs. For a generation and transmission cooperative association, this requirement shall apply to each association's members' aggregate gross operating revenue from sale of electricity to residential customers in the state. Beginning in 2010, a utility or association that furnishes electric service must spend 0.2 percent of its gross operating revenue from residential customers in the state on low-income programs.

(b) To meet the requirements of paragraph (a), a utility or association may contribute money to the energy and conservation account. An energy conservation improvement plan must state the amount, if any, of low-income energy conservation improvement funds the utility or association will contribute to the energy and conservation account. Contributions must be remitted to the commissioner by February 1 of each year.

(c) The commissioner shall establish low-income programs to utilize money contributed to the energy and conservation account under paragraph (b). In establishing low-income programs, the commissioner shall consult political subdivisions, utilities, and nonprofit and community organizations, especially organizations engaged in providing energy and weatherization assistance to low-income persons. Money contributed to the energy and conservation account under paragraph (b) must provide programs for low-income persons, including low-income renters, in the service territory of the utility or association providing the money. The commissioner shall record and report expenditures and energy savings achieved as a result of low-income programs funded through the energy and conservation account in the report required under subdivision 1c, paragraph (g). The commissioner may contract with a political subdivision, nonprofit or community organization, public utility, municipality, or cooperative electric association to implement low-income programs funded through the energy and conservation account.

(d) A utility or association may petition the commissioner to modify its required spending under paragraph (a) if the utility or association and the commissioner have been unable to expend the amount required under paragraph (a) for three consecutive years.

(e) The costs and benefits associated with any approved low-income gas or electric conservation improvement program that is not cost-effective when considering the costs and benefits to the utility may, at the discretion of the utility, be excluded from the calculation of net economic benefits for purposes of calculating the financial incentive to the utility. The energy and demand savings may, at the discretion of the utility, be applied toward the calculation of overall portfolio energy and demand savings for purposes of determining progress toward annual goals and in the financial incentive mechanism.

Subd. 8.Assessment.

The commission or department may assess utilities subject to this section in proportion to their respective gross operating revenue from sales of gas or electric service within the state during the last calendar year to carry out the purposes of subdivisions 1d, 1e, and 1f. Those assessments are not subject to the cap on assessments provided by section 216B.62, or any other law.

Subd. 9.Building performance standards; Sustainable Building 2030.

(a) The purpose of this subdivision is to establish cost-effective energy-efficiency performance standards for new and substantially reconstructed commercial, industrial, and institutional buildings that can significantly reduce carbon dioxide emissions by lowering energy use in new and substantially reconstructed buildings. For the purposes of this subdivision, the establishment of these standards may be referred to as Sustainable Building 2030.

(b) The commissioner shall contract with the Center for Sustainable Building Research at the University of Minnesota to coordinate development and implementation of energy-efficiency performance standards, strategic planning, research, data analysis, technology transfer, training, and other activities related to the purpose of Sustainable Building 2030. The commissioner and the Center for Sustainable Building Research shall, in consultation with utilities, builders, developers, building operators, and experts in building design and technology, develop a Sustainable Building 2030 implementation plan that must address, at a minimum, the following issues:

(1) training architects to incorporate the performance standards in building design;

(2) incorporating the performance standards in utility conservation improvement programs; and

(3) developing procedures for ongoing monitoring of energy use in buildings that have adopted the performance standards.

The plan must be submitted to the chairs and ranking minority members of the senate and house of representatives committees with primary jurisdiction over energy policy by July 1, 2009.

(c) Sustainable Building 2030 energy-efficiency performance standards must be firm, quantitative measures of total building energy use and associated carbon dioxide emissions per square foot for different building types and uses, that allow for accurate determinations of a building's conformance with a performance standard. Performance standards must address energy use by electric vehicle charging infrastructure in or adjacent to buildings as that infrastructure begins to be made widely available. The energy-efficiency performance standards must be updated every three or five years to incorporate all cost-effective measures. The performance standards must reflect the reductions in carbon dioxide emissions per square foot resulting from actions taken by utilities to comply with the renewable energy standards in section 216B.1691. The performance standards should be designed to achieve reductions equivalent to the following reduction schedule, measured against energy consumption by an average building in each applicable building sector in 2003: (1) 60 percent in 2010; (2) 70 percent in 2015; (3) 80 percent in 2020; and (4) 90 percent in 2025. A performance standard must not be established or increased absent a conclusive engineering analysis that it is cost-effective based upon established practices used in evaluating utility conservation improvement programs.

(d) The annual amount of the contract with the Center for Sustainable Building Research is up to $500,000. The Center for Sustainable Building Research shall expend no more than $150,000 of this amount each year on administration, coordination, and oversight activities related to Sustainable Building 2030. The balance of contract funds must be spent on substantive programmatic activities allowed under this subdivision that may be conducted by the Center for Sustainable Building Research and others, and for subcontracts with not-for-profit energy organizations, architecture and engineering firms, and other qualified entities to undertake technical projects and activities in support of Sustainable Building 2030. The primary work to be accomplished each year by qualified technical experts under subcontracts is the development and thorough justification of recommendations for specific energy-efficiency performance standards. Additional work may include:

(1) research, development, and demonstration of new energy-efficiency technologies and techniques suitable for commercial, industrial, and institutional buildings;

(2) analysis and evaluation of practices in building design, construction, commissioning and operations, and analysis and evaluation of energy use in the commercial, industrial, and institutional sectors;

(3) analysis and evaluation of the effectiveness and cost-effectiveness of Sustainable Building 2030 performance standards, conservation improvement programs, and building energy codes;

(4) development and delivery of training programs for architects, engineers, commissioning agents, technicians, contractors, equipment suppliers, developers, and others in the building industries; and

(5) analysis and evaluation of the effect of building operations on energy use.

(e) The commissioner shall require utilities to develop and implement conservation improvement programs that are expressly designed to achieve energy efficiency goals consistent with the Sustainable Building 2030 performance standards. These programs must include offerings of design assistance and modeling, financial incentives, and the verification of the proper installation of energy-efficient design components in new and substantially reconstructed buildings. A utility's design assistance program must consider the strategic planting of trees and shrubs around buildings as an energy conservation strategy for the designed project. A utility making an expenditure under its conservation improvement program that results in a building meeting the Sustainable Building 2030 performance standards may claim the energy savings toward its energy-savings goal established in subdivision 1c.

(f) The commissioner shall report to the legislature every three years, beginning January 15, 2010, on the cost-effectiveness and progress of implementing the Sustainable Building 2030 performance standards and shall make recommendations on the need to continue the program as described in this section.

Subd. 10.Waste heat recovery; thermal energy distribution.

Demand-side natural gas or electric energy displaced by use of waste heat recovered and used as thermal energy, including the recovered thermal energy from a cogeneration or combined heat and power facility, is eligible to be counted towards a utility's natural gas or electric energy savings goals, subject to department approval.

216B.2411 DISTRIBUTED ENERGY RESOURCES.

Subdivision 1.Generation projects.

(a) Any municipality or rural electric association providing electric service and subject to section 216B.241 may, and each public utility may, use five percent of the total amount to be spent on energy conservation improvements under section 216B.241, on:

(1) projects in Minnesota to construct an electric generating facility that utilizes eligible renewable energy sources as defined in subdivision 2, such as methane or other combustible gases derived from the processing of plant or animal wastes, biomass fuels such as short-rotation woody or fibrous agricultural crops, or other renewable fuel, as its primary fuel source;

(2) projects in Minnesota to install a distributed generation facility of ten megawatts or less of interconnected capacity that is fueled by natural gas, renewable fuels, or another similarly clean fuel; or

(3) projects in Minnesota to install a qualifying solar energy project as defined in subdivision 2.

(b) A municipality, rural electric association, or public utility that offers a program to customers to promote installing qualifying solar energy projects may request authority from the commissioner to exceed the five percent limit in paragraph (a), but not to exceed ten percent, to meet customer demand for installation of qualifying solar energy projects. In considering this request, the commissioner shall consider customer interest in qualifying solar energy and the impact on other customers. A municipality, rural electric association, or public utility may not participate in a qualifying solar energy project on a property unless it is provided evidence that all reasonable cost-effective conservation investments have previously been made to the property.

(c) For a municipality, rural electric association, or public utility, projects under this section must be considered energy conservation improvements as defined in section 216B.241.

Subd. 2.Definitions.

(a) For the purposes of this section, the terms defined in this subdivision and section 216B.241, subdivision 1, have the meanings given them.

(b) "Eligible renewable energy sources" means fuels and technologies to generate electricity through the use of any of the resources listed in section 216B.1691, subdivision 1, paragraph (a), except that the incineration of wastewater sludge is not an eligible renewable energy source, "biomass" has the meaning provided under paragraph (c), and "solar" must be from a qualified solar energy project as defined in paragraph (d).

(c) "Biomass" includes:

(1) methane or other combustible gases derived from the processing of plant or animal material;

(2) alternative fuels derived from soybean and other agricultural plant oils or animal fats;

(3) combustion of barley hulls, corn, soy-based products, or other agricultural products;

(4) wood residue from the wood products industry in Minnesota or other wood products such as short-rotation woody or fibrous agricultural crops;

(5) landfill gas;

(6) the predominantly organic components of wastewater effluent, sludge, or related by-products from publicly owned treatment works; and

(7) mixed municipal solid waste, and refuse-derived fuel from mixed municipal solid waste.

(d) "Qualifying solar energy project" means a qualifying solar thermal project or qualifying solar electric project.

(e) "Qualifying solar thermal project" means a flat plate or evacuated tube that meets the requirements of section 216C.25 with a fixed orientation that collects the sun's radiant energy and transfers it to a storage medium for distribution as energy to heat or cool air or water, but does not include equipment used to heat water at a residential property (1) for domestic use if less than one-half of the energy used for that purpose is derived from the sun or (2) for use in a hot tub or swimming pool.

(f) "Qualifying solar electric project" means:

(1) solar electric equipment that: (i) meets the requirements of section 216C.25; (ii) has a peak generating capacity of 100 kilowatts or less; and (iii) is used to generate electricity for use in a residential, commercial, or publicly owned property or facility; and

(2) if applicable, equipment that is used to store the electricity generated by a qualified solar electric project under clause (1) and that is located proximate to the property or facility using the electricity.

(g) "Residential property" means the principal residence of a homeowner at the time the solar equipment is placed in service.

Subd. 3.Other provisions.

(a) Electricity generated by a facility constructed with funds provided under this section and using an eligible renewable energy source may be counted toward the renewable energy objectives in section 216B.1691, subject to the provisions of that section, except as provided in paragraph (c).

(b) Two or more entities may pool resources under this section to provide assistance jointly to proposed eligible renewable energy projects. The entities shall negotiate and agree among themselves for allocation of benefits associated with a project, such as the ability to count energy generated by a project toward a utility's renewable energy objectives under section 216B.1691, except as provided in paragraph (c). The entities shall provide a summary of the allocation of benefits to the commissioner. A utility may spend funds under this section for projects in Minnesota that are outside the service territory of the utility.

(c) Electricity generated by a solar photovoltaic device constructed with funds provided under this section may be counted toward a public utility's solar energy standard under section 216B.1691, subdivision 2f.

216B.2412 DECOUPLING OF ENERGY SALES FROM REVENUES.

Subdivision 1.Definition and purpose.

For the purpose of this section, "decoupling" means a regulatory tool designed to separate a utility's revenue from changes in energy sales. The purpose of decoupling is to reduce a utility's disincentive to promote energy efficiency.

Subd. 2.Decoupling criteria.

The commission shall, by order, establish criteria and standards for decoupling. The commission may establish these criteria and standards in a separate proceeding or in a general rate case or other proceeding in which it approves a pilot program, and shall design the criteria and standards to mitigate the impact on public utilities of the energy-savings goals under section 216B.241 without adversely affecting utility ratepayers. In designing the criteria, the commission shall consider energy efficiency, weather, and cost of capital, among other factors.

Subd. 3.Pilot programs.

The commission shall allow one or more rate-regulated utilities to participate in a pilot program to assess the merits of a rate-decoupling strategy to promote energy efficiency and conservation. Each pilot program must utilize the criteria and standards established in subdivision 2 and be designed to determine whether a rate-decoupling strategy achieves energy savings. On or before a date established by the commission, the commission shall require electric and gas utilities that intend to implement a decoupling program to file a decoupling pilot plan, which shall be approved or approved as modified by the commission. A pilot program may not exceed three years in length. Any extension beyond three years can only be approved in a general rate case, unless that decoupling program was previously approved as part of a general rate case. The commission shall report on the programs annually to the chairs of the house of representatives and senate committees with primary jurisdiction over energy policy.

216B.242 [Repealed, 2011 c 97 s 34]

RENEWABLE ENERGY INITIATIVES

216B.2421 DEFINITION OF LARGE ENERGY FACILITY.

Subdivision 1.Applicability.

The definition in this section applies to this section and sections 216B.2422 and 216B.243.

Subd. 2.Large energy facility.

"Large energy facility" means:

(1) any electric power generating plant or combination of plants at a single site with a combined capacity of 50,000 kilowatts or more and transmission lines directly associated with the plant that are necessary to interconnect the plant to the transmission system;

(2) any high-voltage transmission line with a capacity of 200 kilovolts or more and greater than 1,500 feet in length;

(3) any high-voltage transmission line with a capacity of 100 kilovolts or more with more than ten miles of its length in Minnesota or that crosses a state line;

(4) any pipeline greater than six inches in diameter and having more than 50 miles of its length in Minnesota used for the transportation of coal, crude petroleum or petroleum fuels or oil, or their derivatives;

(5) any pipeline for transporting natural or synthetic gas at pressures in excess of 200 pounds per square inch with more than 50 miles of its length in Minnesota;

(6) any facility designed for or capable of storing on a single site more than 100,000 gallons of liquefied natural gas or synthetic gas;

(7) any underground gas storage facility requiring a permit pursuant to section 103I.681;

(8) any nuclear fuel processing or nuclear waste storage or disposal facility; and

(9) any facility intended to convert any material into any other combustible fuel and having the capacity to process in excess of 75 tons of the material per hour.

Subd. 3.

[Repealed, 2001 c 212 art 7 s 36]

216B.2422 RESOURCE PLANNING; RENEWABLE ENERGY.

Subdivision 1.Definitions.

(a) For purposes of this section, the terms defined in this subdivision have the meanings given them.

(b) "Utility" means an entity with the capability of generating 100,000 kilowatts or more of electric power and serving, either directly or indirectly, the needs of 10,000 retail customers in Minnesota. Utility does not include federal power agencies.

(c) "Renewable energy" means electricity generated through use of any of the following resources:

(1) wind;

(2) solar;

(3) geothermal;

(4) hydro;

(5) trees or other vegetation;

(6) landfill gas; or

(7) predominantly organic components of wastewater effluent, sludge, or related by-products from publicly owned treatment works, but not including incineration of wastewater sludge.

(d) "Resource plan" means a set of resource options that a utility could use to meet the service needs of its customers over a forecast period, including an explanation of the supply and demand circumstances under which, and the extent to which, each resource option would be used to meet those service needs. These resource options include using, refurbishing, and constructing utility plant and equipment, buying power generated by other entities, controlling customer loads, and implementing customer energy conservation.

(e) "Refurbish" means to rebuild or substantially modify an existing electricity generating resource of 30 megawatts or greater.

Subd. 2.Resource plan filing and approval.

A utility shall file a resource plan with the commission periodically in accordance with rules adopted by the commission. The commission shall approve, reject, or modify the plan of a public utility, as defined in section 216B.02, subdivision 4, consistent with the public interest. In the resource plan proceedings of all other utilities, the commission's order shall be advisory and the order's findings and conclusions shall constitute prima facie evidence which may be rebutted by substantial evidence in all other proceedings. With respect to utilities other than those defined in section 216B.02, subdivision 4, the commission shall consider the filing requirements and decisions in any comparable proceedings in another jurisdiction. As a part of its resource plan filing, a utility shall include the least cost plan for meeting 50 and 75 percent of all new and refurbished capacity needs through a combination of conservation and renewable energy resources.

Subd. 2a.Historical data and advance forecast.

Each utility required to file a resource plan under this section shall include in the filing all applicable annual information required by section 216C.17, subdivision 2, and the rules adopted under that section. To the extent that a utility complies with this subdivision, it is not required to file annual advance forecasts with the department under section 216C.17, subdivision 2.

Subd. 2b.Optional integrated resource plan compliance for certain cooperatives.

For the purposes of this subdivision, a "cooperative" means a generating and transmission cooperative electric association that has at least 80 percent of its member distribution cooperatives located outside of Minnesota and that provides less than four percent of the electricity annually sold at retail in the state of Minnesota. A cooperative may, in lieu of filing a resource plan under subdivision 2, elect to file a report to the commission under this subdivision. The report must include projected demand levels for the next 15 years and generation resources to meet any projected generation deficiencies. To supply the information required in a report under this subdivision, a cooperative may use reports submitted under section 216C.17, subdivision 2, reports to regional reliability organizations, or similar reports submitted to other state utility commissions. A report must be submitted annually by July 1, but the commission may extend the time if it finds the extension in the public interest. Presentation of the annual report shall be done in accordance with procedures established by the commission. Data in a report under this subdivision may be aggregate data and need not be separately reported for individual distribution cooperative members of the cooperative. The commission may take whatever action in response to a report under this subdivision that it could take with respect to a report by a cooperative under subdivision 2.

[See Note.]

Subd. 3.Environmental costs.

(a) The commission shall, to the extent practicable, quantify and establish a range of environmental costs associated with each method of electricity generation. A utility shall use the values established by the commission in conjunction with other external factors, including socioeconomic costs, when evaluating and selecting resource options in all proceedings before the commission, including resource plan and certificate of need proceedings.

(b) The commission shall establish interim environmental cost values associated with each method of electricity generation by March 1, 1994. These values expire on the date the commission establishes environmental cost values under paragraph (a).

Subd. 4.Preference for renewable energy facility.

The commission shall not approve a new or refurbished nonrenewable energy facility in an integrated resource plan or a certificate of need, pursuant to section 216B.243, nor shall the commission allow rate recovery pursuant to section 216B.16 for such a nonrenewable energy facility, unless the utility has demonstrated that a renewable energy facility is not in the public interest. The public interest determination must include whether the resource plan helps the utility achieve the greenhouse gas reduction goals under section 216H.02, the renewable energy standard under section 216B.1691, or the solar energy standard under section 216B.1691, subdivision 2f.

Subd. 5.Bidding; exemption from certificate of need proceeding.

(a) A utility may select resources to meet its projected energy demand through a bidding process approved or established by the commission. A utility shall use the environmental cost estimates determined under subdivision 3 in evaluating bids submitted in a process established under this subdivision.

(b) Notwithstanding any other provision of this section, if an electric power generating plant, as described in section 216B.2421, subdivision 2, clause (1), is selected in a bidding process approved or established by the commission, a certificate of need proceeding under section 216B.243 is not required.

(c) A certificate of need proceeding is also not required for an electric power generating plant that has been selected in a bidding process approved or established by the commission, or such other selection process approved by the commission, to satisfy, in whole or in part, the wind power mandate of section 216B.2423 or the biomass mandate of section 216B.2424.

Subd. 6.Consolidation of resource planning and certificate of need.

A utility shall indicate in its resource plan whether it intends to site or construct a large energy facility. If the utility's resource plan includes a proposed large energy facility and construction of that facility is likely to begin before the utility files its next resource plan, the commission shall conduct the resource plan proceeding consistent with the requirements of section 216B.243 with respect to the proposed facility. If the commission approves the proposed facility in the resource plan, a separate certificate of need proceeding is not required.

NOTE: A cooperative must complete an integrated resource plan pending on May 3, 2012, under subdivision 2 before it may make an election under subdivision 2b, as added by Laws 2012, chapter 268, section 1. Laws 2012, chapter 268, section 1, the effective date.

216B.2423 WIND POWER MANDATE.

Subdivision 1.Mandate.

A public utility, as defined in section 216B.02, subdivision 4, that operates a nuclear-powered electric generating plant within this state must construct and operate, purchase, or contract to construct and operate: (1) 225 megawatts of electric energy installed capacity generated by wind energy conversion systems within the state by December 31, 1998; and (2) an additional 200 megawatts of installed capacity so generated by December 31, 2002.

For the purpose of this section, "wind energy conversion system" has the meaning given it in section 216C.06, subdivision 19.

Subd. 2.Resource planning mandate.

The Public Utilities Commission shall order a public utility subject to subdivision 1, to construct and operate, purchase, or contract to purchase an additional 400 megawatts of electric energy installed capacity generated by wind energy conversion systems by December 31, 2002, subject to resource planning and least cost planning requirements in section 216B.2422.

Subd. 2a.Site preference.

The Public Utilities Commission shall ensure that a utility subject to the requirements of subdivision 1, clause (2), shall implement that clause with a preference for wind energy conversion systems within the state. This preference shall not prevent the utility from constructing or contracting to construct wind energy conversion systems outside the state, if the Public Utilities Commission determines that selection of a facility within the state conflicts with the requirements of section 216B.03.

Subd. 3.Standard contract for wind energy conversion systems.

The Public Utilities Commission shall require a public utility subject to subdivision 1 to develop and file in a form acceptable to the commission by October 1, 1997, a standard form contract for the purchase of electricity from wind conversion systems with installed capacity of two megawatts and less. For purposes of applying the two megawatts limit, the installed capacity sold to the public utility from a single seller or affiliated group of sellers shall be cumulated. The standard contract shall include all the terms and conditions for purchasing wind-generated power by the utility, except for price and any other specific terms necessary to ensure system reliability and safety, which shall be separately negotiable.

216B.2424 BIOMASS POWER MANDATE.

Subdivision 1.Farm-grown closed-loop biomass.

(a) For the purposes of this section, "farm-grown closed-loop biomass" means herbaceous crops, trees, agricultural waste, and aquatic plant matter that is used to generate electricity, but does not include mixed municipal solid waste, as defined in section 115A.03, and that:

(1) is intentionally cultivated, harvested, and prepared for use, in whole or in part, as a fuel for the generation of electricity;

(2) when combusted, releases an amount of carbon dioxide that is less than or approximately equal to the carbon dioxide absorbed by the biomass fuel during its growing cycle; and

(3) is fired in a new or substantially retrofitted electric generating facility that is:

(i) located within 400 miles of the site of the biomass production; and

(ii) designed to use biomass to meet at least 75 percent of its fuel requirements.

(b) The legislature finds that the negative environmental impacts within 400 miles of the facility resulting from transporting and combusting the biomass are offset in that region by the environmental benefits to air, soil, and water of the biomass production.

(c) Among the biomass fuel sources that meet the requirements of paragraph (a), clauses (1) and (2), are poplar, aspen, willow, switch grass, sorghum, alfalfa, cultivated prairie grass, and sustainably managed woody biomass.

(d) For the purpose of this section, "sustainably managed woody biomass" means:

(1) brush, trees, and other biomass harvested from within designated utility, railroad, and road rights-of-way;

(2) upland and lowland brush harvested from lands incorporated into brushland habitat management activities of the Minnesota Department of Natural Resources;

(3) upland and lowland brush harvested from lands managed in accordance with Minnesota Department of Natural Resources "Best Management Practices for Managing Brushlands";

(4) logging slash or waste wood that is created by harvest, by precommercial timber stand improvement to meet silvicultural objectives, or by fire, disease, or insect control treatments, and that is managed in compliance with the Minnesota Forest Resources Council's "Sustaining Minnesota Forest Resources: Voluntary Site-Level Forest Management Guidelines for Landowners, Loggers and Resource Managers" as modified by the requirement of this subdivision; and

(5) trees or parts of trees that do not meet the utilization standards for pulpwood, posts, bolts, or sawtimber as described in the Minnesota Department of Natural Resources Division of Forestry Timber Sales Manual, 1998, as amended as of May 1, 2005, and the Minnesota Department of Natural Resources Timber Scaling Manual, 1981, as amended as of May 1, 2005, except as provided in paragraph (a), clause (1), and this paragraph, clauses (1) to (3).

Subd. 1a.Municipal waste-to-energy project.

(a) This subdivision applies only to a biomass project owned or controlled, directly or indirectly, by two municipal utilities as described in subdivision 5a, paragraph (b).

(b) Woody biomass from state-owned land must be harvested in compliance with an adopted management plan and a program of ecologically based third-party certification.

(c) The project must prepare a fuel plan on an annual basis after commercial operation of the project as described in the power contract between the project and the public utility, and must also prepare annually certificates reflecting the types of fuel used in the preceding year by the project, as described in the power contract. The fuel plans and certificates shall also be filed with the Minnesota Department of Natural Resources and the Minnesota Department of Commerce within 30 days after being provided to the public utility, as provided by the power contract. Any person who believes the fuel plans, as amended, and certificates show that the project does not or will not comply with the fuel requirements of this subdivision may file a petition with the commission seeking such a determination.

(d) The wood procurement process must utilize third-party audit certification systems to verify that applicable best management practices were utilized in the procurement of the sustainably managed biomass. If there is a failure to so verify in any two consecutive years during the original contract term, the farm-grown closed-loop biomass requirements of subdivision 2 must be increased to 50 percent for the remaining contract term period; however, if in two consecutive subsequent years after the increase has been implemented, it is verified that the conditions in this subdivision have been met, then for the remaining original contract term the closed-loop biomass mandate reverts to 25 percent. If there is a subsequent failure to verify in a year after the first failure and implementation of the 50 percent requirement, then the closed-loop percentage shall remain at 50 percent for each remaining year of the contract term.

(e) In the closed-loop plantation, no transgenic plants may be used.

(f) No wood may be harvested from any lands identified by the final or preliminary Minnesota County Biological Survey as having statewide significance as native plant communities, large populations or concentrations of rare species, or critical animal habitat.

(g) A wood procurement plan must be prepared every five years and public meetings must be held and written comments taken on the plan and documentation must be provided on why or why not the public inputs were used.

(h) Guidelines or best management practices for sustainably managed woody biomass must be adopted by:

(1) the Minnesota Department of Natural Resources for managing and maintaining brushland and open land habitat on public and private lands, including, but not limited to, provisions of sections 84.941, 84.942, and 97A.125; and

(2) the Minnesota Forest Resources Council for logging slash, using the most recent available scientific information regarding the removal of woody biomass from forest lands, to sustain the management of forest resources as defined by section 89.001, subdivisions 8 and 9, with particular attention to soil productivity, biological diversity as defined by section 89A.01, subdivision 3, and wildlife habitat.

These guidelines must be completed by July 1, 2007, and the process of developing them must incorporate public notification and comment.

(i) The University of Minnesota Initiative for Renewable Energy and the Environment is encouraged to solicit and fund high-quality research projects to develop and consolidate scientific information regarding the removal of woody biomass from forest and brush lands, with particular attention to the environmental impacts on soil productivity, biological diversity, and sequestration of carbon. The results of this research shall be made available to the public.

(j) The two utilities owning or controlling, directly or indirectly, the biomass project described in subdivision 5a, paragraph (b), shall fund or obtain funding from nonstate sources of up to $150,000 by April 1, 2006, to complete the guidelines or best management practices described in paragraph (h). The expenditures to be funded under this paragraph do not include any of the expenditures to be funded under paragraph (i).

Subd. 2.Interim exemption.

(a) A biomass project proposing to use, as its primary fuel over the life of the project, short-rotation woody crops, may use as an interim fuel agricultural waste and other biomass which is not farm-grown closed-loop biomass for up to six years after the project's electric generating facility becomes operational; provided, the project developer demonstrates the project will use the designated short-rotation woody crops as its primary fuel after the interim period and provided the location of the interim fuel production meets the requirements of subdivision 1, paragraph (a), clause (3).

(b) A biomass project proposing to use, as its primary fuel over the life of the project, short-rotation woody crops, may use as an interim fuel agricultural waste and other biomass which is not farm-grown closed-loop biomass for up to three years after the project's electric generating facility becomes operational; provided, the project developer demonstrates the project will use the designated short-rotation woody crops as its primary fuel after the interim period.

(c) A biomass project that uses an interim fuel under the terms of paragraph (b) may, in addition, use an interim fuel under the terms of paragraph (a) for six years less the number of years that an interim fuel was used under paragraph (b).

(d) A project developer proposing to use an exempt interim fuel under paragraphs (a) and (b) must demonstrate to the public utility that the project will have an adequate supply of short-rotation woody crops which meet the requirements of subdivision 1 to fuel the project after the interim period.

(e) If a biomass project using an interim fuel under this subdivision is or becomes owned or controlled, directly or indirectly, by two municipal utilities as described in subdivision 5a, paragraph (b), the project is deemed to comply with the requirement under this subdivision to use as its primary fuel farm-grown closed-loop biomass if farm-grown closed-loop biomass comprises no less than 25 percent of the fuel used over the life of the project. For purposes of this subdivision, "life of the project" means 20 years from the date the project becomes operational or the term of the applicable power purchase agreement between the project owner and the public utility, whichever is longer.

Subd. 3.Fuel exemption.

Over the duration of the contract of a biomass power facility selected to satisfy the mandate in subdivision 5, fuel sources that are not biomass may be used to satisfy up to 25 percent of the fuel requirements of a biomass power facility selected to satisfy the biomass power mandate in subdivision 5, except that agricultural crop wastes, such as oat hulls, may be used to satisfy more than 25 percent of the fuel requirements of a power facility selected to satisfy the biomass power mandate in subdivision 5 if the wastes are co-fired with the fuel authorized for the facility. A biomass power facility selected to satisfy the mandate in subdivision 5 also may use fuel sources that are not biomass during any period when biomass fuel sources are not reasonably available to the facility due to any circumstances constituting an act of God. Fuel sources that are not biomass used during such a period of biomass fuel source unavailability shall not be counted toward the 25 percent exemption provided in this subdivision. For purposes of this subdivision, "act of God" means any natural disaster or other natural phenomenon of an exceptional, inevitable, or irresistible character, including, but not limited to, flood, fire, drought, earthquake, and crop failure resulting from climatic conditions, infestation, or disease.

Subd. 4.Financial viability.

A biomass project developer must demonstrate to the public utility evidence of sufficient financial viability necessary for the construction and operation of the biomass project.

Subd. 5.Mandate.

(a) A public utility, as defined in section 216B.02, subdivision 4, that operates a nuclear-powered electric generating plant within this state must construct and operate, purchase, or contract to construct and operate (1) by December 31, 1998, 50 megawatts of electric energy installed capacity generated by farm-grown closed-loop biomass scheduled to be operational by December 31, 2001; and (2) by December 31, 1998, an additional 75 megawatts of installed capacity so generated scheduled to be operational by December 31, 2002.

(b) Of the 125 megawatts of biomass electricity installed capacity required under this subdivision, no more than 55 megawatts of this capacity may be provided by a facility that uses poultry litter as its primary fuel source and any such facility:

(1) need not use biomass that complies with the definition in subdivision 1;

(2) must enter into a contract with the public utility for such capacity, that has an average purchase price per megawatt hour over the life of the contract that is equal to or less than the average purchase price per megawatt hour over the life of the contract in contracts approved by the Public Utilities Commission before April 1, 2000, to satisfy the mandate of this section, and file that contract with the Public Utilities Commission prior to September 1, 2000; and

(3) must schedule such capacity to be operational by December 31, 2002.

(c) Of the total 125 megawatts of biomass electric energy installed capacity required under this section, no more than 75 megawatts may be provided by a single project.

(d) Of the 75 megawatts of biomass electric energy installed capacity required under paragraph (a), clause (2), no more than 33 megawatts of this capacity may be provided by a St. Paul district heating and cooling system cogeneration facility utilizing waste wood as a primary fuel source. The St. Paul district heating and cooling system cogeneration facility need not use biomass that complies with the definition in subdivision 1.

(e) The public utility must accept and consider on an equal basis with other biomass proposals:

(1) a proposal to satisfy the requirements of this section that includes a project that exceeds the megawatt capacity requirements of either paragraph (a), clause (1) or (2), and that proposes to sell the excess capacity to the public utility or to other purchasers; and

(2) a proposal for a new facility to satisfy more than ten but not more than 20 megawatts of the electrical generation requirements by a small business-sponsored independent power producer facility to be located within the northern quarter of the state, which means the area located north of Constitutional Route No. 8 as described in section 161.114, subdivision 2, and that utilizes biomass residue wood, sawdust, bark, chipped wood, or brush to generate electricity. A facility described in this clause is not required to utilize biomass complying with the definition in subdivision 1, but must be under construction by December 31, 2005.

(f) If a public utility files a contract with the commission for electric energy installed capacity that uses poultry litter as its primary fuel source, the commission must do a preliminary review of the contract to determine if it meets the purchase price criteria provided in paragraph (b), clause (2). The commission shall perform its review and advise the parties of its determination within 30 days of filing of such a contract by a public utility. A public utility may submit by September 1, 2000, a revised contract to address the commission's preliminary determination.

(g) The commission shall finally approve, modify, or disapprove no later than July 1, 2001, all contracts submitted by a public utility as of September 1, 2000, to meet the mandate set forth in this subdivision.

(h) If a public utility subject to this section exercises an option to increase the generating capacity of a project in a contract approved by the commission prior to April 25, 2000, to satisfy the mandate in this subdivision, the public utility must notify the commission by September 1, 2000, that it has exercised the option and include in the notice the amount of additional megawatts to be generated under the option exercised. Any review by the commission of the project after exercise of such an option shall be based on the same criteria used to review the existing contract.

(i) A facility specified in this subdivision qualifies for exemption from property taxation under section 272.02, subdivision 45.

Subd. 5a.Reduction of biomass mandate.

(a) Notwithstanding subdivision 5, the biomass electric energy mandate must be reduced from 125 megawatts to 110 megawatts.

(b) The Public Utilities Commission shall approve a request pending before the commission as of May 15, 2003, for amendments to and assignment of a power purchase agreement with the owner of a facility that uses short-rotation, woody crops as its primary fuel previously approved to satisfy a portion of the biomass mandate if the owner of the project agrees to reduce the size of its project from 50 megawatts to 35 megawatts, while maintaining an average price for energy in nominal dollars measured over the term of the power purchase agreement at or below $104 per megawatt-hour, exclusive of any price adjustments that may take effect subsequent to commission approval of the power purchase agreement, as amended. The commission shall also approve, as necessary, any subsequent assignment or sale of the power purchase agreement or ownership of the project to an entity owned or controlled, directly or indirectly, by two municipal utilities located north of Constitutional Route No. 8, as described in section 161.114, which currently own electric and steam generation facilities using coal as a fuel and which propose to retrofit their existing municipal electrical generating facilities to utilize biomass fuels in order to perform the power purchase agreement.

(c) If the power purchase agreement described in paragraph (b) is assigned to an entity that is, or becomes, owned or controlled, directly or indirectly, by two municipal entities as described in paragraph (b), and the power purchase agreement meets the price requirements of paragraph (b), the commission shall approve any amendments to the power purchase agreement necessary to reflect the changes in project location and ownership and any other amendments made necessary by those changes. The commission shall also specifically find that:

(1) the power purchase agreement complies with and fully satisfies the provisions of this section to the full extent of its 35-megawatt capacity;

(2) all costs incurred by the public utility and all amounts to be paid by the public utility to the project owner under the terms of the power purchase agreement are fully recoverable pursuant to section 216B.1645;

(3) subject to prudency review by the commission, the public utility may recover from its Minnesota retail customers the amounts that may be incurred and paid by the public utility during the full term of the power purchase agreement; and

(4) if the purchase power agreement meets the requirements of this subdivision, it is reasonable and in the public interest.

(d) The commission shall specifically approve recovery by the public utility of any and all Minnesota jurisdictional costs incurred by the public utility to improve, construct, install, or upgrade transmission, distribution, or other electrical facilities owned by the public utility or other persons in order to permit interconnection of the retrofitted biomass-fueled generating facilities or to obtain transmission service for the energy provided by the facilities to the public utility pursuant to section 216B.1645, and shall disapprove any provision in the power purchase agreement that requires the developer or owner of the project to pay the jurisdictional costs or that permit the public utility to terminate the power purchase agreement as a result of the existence of those costs or the public utility's obligation to pay any or all of those costs.

(e) Upon request by the project owner, the public utility shall agree to amend the power purchase agreement described in paragraph (b) and approved by the commission as required by paragraph (c). The amendment must be negotiated and executed within 45 days of May 14, 2013, and must apply to prices paid after January 1, 2014. The average price for energy in nominal dollars measured over the term of the power purchase agreement must not exceed $109.20 per megawatt hour. The public utility shall request approval of the amendment by the commission within 30 days of execution of the amended power purchase agreement. The amendment is not effective until approval by the commission. The commission shall act on the amendment within 90 days of submission of the request by the public utility. Upon approval of the amended power purchase agreement, the commission shall allow the public utility to recover the costs of the amended power purchase agreement, as provided in section 216B.1645.

(f) With respect to the power purchase agreement described in paragraph (b), and amended and approved by the commission pursuant to paragraphs (c) and (e), upon request by the project owner, the public utility shall agree to amend the power purchase agreement to include a fuel cost adjustment clause which requires the public utility to reimburse the project owner monthly for all costs incurred by the project owner during the applicable month to procure and transport all fuel used to produce energy for delivery to the public utility pursuant to the power purchase agreement to the extent such costs exceeded $3.40 per million metric British thermal unit (MMBTU), in addition to the price to be paid for the energy produced and delivered by the project owner. Beginning with 2014, at the end of each calendar year of the term of the power purchase agreement, the project owner shall calculate the amount by which actual fuel costs for the year exceeded $3.40 per MMBTU, and prior monthly payment for such fuel costs shall be reconciled against actual fuel costs for the applicable calendar year. If such prior monthly fuel payments for the year in the aggregate exceed the amount due based on the annual calculation, the project owner shall credit the public utility for the excess paid. If the annual calculation of fuel costs due exceeds the prior monthly fuel payments for the year in the aggregate, the project owner shall be entitled to be paid for the deficiency with the next invoice to the public utility. The amendment shall be negotiated and executed within 45 days of May 13, 2013, and shall be effective for fuel costs incurred and prices after January 1, 2014. The public utility shall request approval of the amendment by the commission, and the commission shall approve the amendment as reasonable and in the public interest and allow the public utility to recover from its Minnesota retail customers the amounts paid by the public utility to the project owner pursuant to the power purchase agreement during the full term of the power purchase agreement, including the reimbursement of fuel costs pursuant to the power purchase agreement amendment, pursuant to section 216B.1645, or otherwise.

(g) With respect to the power purchase agreement described in paragraph (b) and approved by the commission pursuant to paragraphs (c) and (e), the public utility is prohibited from recovering from the project owner any costs which were not actually and reasonably incurred by the utility, notwithstanding any provision in the power purchase agreement to the contrary. In addition, beginning with 2012, the public utility shall pay for all energy delivered by the project owner pursuant to the power purchase agreement at the full price for such energy in the power purchase agreement approved and amended pursuant to paragraph (e), provided that the project owner does not deliver more than 110 percent of the amount scheduled for delivery in any year of the power purchase agreement, and does not deliver, on average over any five consecutive years of the power purchase agreement, an amount greater than 105 percent of the amount scheduled for delivery over the five-year period.

Subd. 6.Remaining megawatt compliance process.

(a) If there remain megawatts of biomass power generating capacity to fulfill the mandate in subdivision 5 after the commission has taken final action on all contracts filed by September 1, 2000, by a public utility, as amended and assigned, this subdivision governs final compliance with the biomass energy mandate in subdivision 5 subject to the requirements of subdivisions 7 and 8.

(b) To the extent not inconsistent with this subdivision, the provisions of subdivisions 2, 3, 4, and 5 apply to proposals subject to this subdivision.

(c) A public utility must submit proposals to the commission to complete the biomass mandate. The commission shall require a public utility subject to this section to issue a request for competitive proposals for projects for electric generation utilizing biomass as defined in paragraph (f) of this subdivision to provide the remaining megawatts of the mandate. The commission shall set an expedited schedule for submission of proposals to the utility, selection by the utility of proposals or projects, negotiation of contracts, and review by the commission of the contracts or projects submitted by the utility to the commission.

(d) Notwithstanding the provisions of subdivisions 1 to 5 but subject to the provisions of subdivisions 7 and 8, a new or existing facility proposed under this subdivision that is fueled either by biomass or by co-firing biomass with nonbiomass may satisfy the mandate in this section. Such a facility need not use biomass that complies with the definition in subdivision 1 if it uses biomass as defined in paragraph (f) of this subdivision. Generating capacity produced by co-firing of biomass that is operational as of April 25, 2000, does not meet the requirements of the mandate, except that additional co-firing capacity added at an existing facility after April 25, 2000, may be used to satisfy this mandate. Only the number of megawatts of capacity at a facility which co-fires biomass that are directly attributable to the biomass and that become operational after April 25, 2000, count toward meeting the biomass mandate in this section.

(e) Nothing in this subdivision precludes a facility proposed and approved under this subdivision from using fuel sources that are not biomass in compliance with subdivision 3.

(f) Notwithstanding the provisions of subdivision 1, for proposals subject to this subdivision, "biomass" includes farm-grown closed-loop biomass; agricultural wastes, including animal, poultry, and plant wastes; and waste wood, including chipped wood, bark, brush, residue wood, and sawdust.

(g) Nothing in this subdivision affects in any way contracts entered into as of April 25, 2000, to satisfy the mandate in subdivision 5.

(h) Nothing in this subdivision requires a public utility to retrofit its own power plants for the purpose of co-firing biomass fuel, nor is a utility prohibited from retrofitting its own power plants for the purpose of co-firing biomass fuel to meet the requirements of this subdivision.

Subd. 7.Effect on existing projects.

The commission may not approve a project proposed after April 25, 2000, which would have an adverse impact on the ability of a project approved before April 25, 2000, to obtain an adequate supply of the fuel source designated for the project.

Subd. 8.Agricultural biomass requirement.

Of the 125 megawatts mandated in subdivision 5, or 110 megawatts mandated in subdivision 5a, at least 75 megawatts of the generating capacity must be generated by facilities that use agricultural biomass as the principal fuel source. For purposes of this subdivision, agricultural biomass includes only farm-grown closed-loop biomass and agricultural waste, including animal, poultry, and plant wastes. For purposes of this subdivision, "principal fuel source" means a fuel source that satisfies at least 75 percent of the fuel requirements of an electric power generating facility. Nothing in this subdivision is intended to expand the fuel source requirements of subdivision 5.

216B.2425 STATE TRANSMISSION PLAN.

Subdivision 1.List.

The commission shall maintain a list of certified high-voltage transmission line projects.

Subd. 2.List development; transmission projects report.

(a) By November 1 of each odd-numbered year, a transmission projects report must be submitted to the commission by each utility, organization, or company that:

(1) is a public utility, a municipal utility, a cooperative electric association, the generation and transmission organization that serves each utility or association, or a transmission company; and

(2) owns or operates electric transmission lines in Minnesota, except a company or organization that owns a transmission line that serves a single customer or interconnects a single generating facility.

(b) The report may be submitted jointly or individually to the commission.

(c) The report must:

(1) list specific present and reasonably foreseeable future inadequacies in the transmission system in Minnesota;

(2) identify alternative means of addressing each inadequacy listed;

(3) identify general economic, environmental, and social issues associated with each alternative; and

(4) provide a summary of public input related to the list of inadequacies and the role of local government officials and other interested persons in assisting to develop the list and analyze alternatives.

(d) To meet the requirements of this subdivision, reporting parties may rely on available information and analysis developed by a regional transmission organization or any subgroup of a regional transmission organization and may develop and include additional information as necessary.

Subd. 3.Commission approval.

By June 1 of each even-numbered year, the commission shall adopt a state transmission project list and shall certify, certify as modified, or deny certification of the projects proposed under subdivision 2. The commission may only certify a project that is a high-voltage transmission line as defined in section 216B.2421, subdivision 2, that the commission finds is:

(1) necessary to maintain or enhance the reliability of electric service to Minnesota consumers;

(2) needed, applying the criteria in section 216B.243, subdivision 3; and

(3) in the public interest, taking into account electric energy system needs and economic, environmental, and social interests affected by the project.

Subd. 4.List; effect.

Certification of a project as a priority electric transmission project satisfies section 216B.243. A certified project on which construction has not begun more than six years after being placed on the list, must be reapproved by the commission.

Subd. 5.Transmission inventory.

The Department of Commerce shall create, maintain, and update annually an inventory of transmission lines in the state.

Subd. 6.Exclusion.

This section does not apply to any transmission line proposal that has been approved by, or was pending before, a local unit of government, the Environmental Quality Board, or the Public Utilities Commission on August 1, 2001.

Subd. 7.Transmission needed to support renewable resources.

(a) Each entity subject to this section shall determine necessary transmission upgrades to support development of renewable energy resources required to meet objectives under section 216B.1691 and shall include those upgrades in its report under subdivision 2.

(b) MS 2008 [Expired]

216B.2426 OPPORTUNITIES FOR DISTRIBUTED GENERATION.

The commission shall ensure that opportunities for the installation of distributed generation, as that term is defined in section 216B.169, subdivision 1, paragraph (c), are considered in any proceeding under section 216B.2422, 216B.2425, or 216B.243.


CERTIFICATE OF NEED

216B.243 CERTIFICATE OF NEED FOR LARGE ENERGY FACILITY.

Subdivision 1.Assessment of need criteria.

The commission shall, pursuant to chapter 14 and sections 216C.05 to 216C.30 and this section, adopt assessment of need criteria to be used in the determination of need for large energy facilities pursuant to this section.

Subd. 2.Certificate required.

No large energy facility shall be sited or constructed in Minnesota without the issuance of a certificate of need by the commission pursuant to sections 216C.05 to 216C.30 and this section and consistent with the criteria for assessment of need.

Subd. 3.Showing required for construction.

No proposed large energy facility shall be certified for construction unless the applicant can show that demand for electricity cannot be met more cost effectively through energy conservation and load-management measures and unless the applicant has otherwise justified its need. In assessing need, the commission shall evaluate:

(1) the accuracy of the long-range energy demand forecasts on which the necessity for the facility is based;

(2) the effect of existing or possible energy conservation programs under sections 216C.05 to 216C.30 and this section or other federal or state legislation on long-term energy demand;

(3) the relationship of the proposed facility to overall state energy needs, as described in the most recent state energy policy and conservation report prepared under section 216C.18, or, in the case of a high-voltage transmission line, the relationship of the proposed line to regional energy needs, as presented in the transmission plan submitted under section 216B.2425;

(4) promotional activities that may have given rise to the demand for this facility;

(5) benefits of this facility, including its uses to protect or enhance environmental quality, and to increase reliability of energy supply in Minnesota and the region;

(6) possible alternatives for satisfying the energy demand or transmission needs including but not limited to potential for increased efficiency and upgrading of existing energy generation and transmission facilities, load-management programs, and distributed generation;

(7) the policies, rules, and regulations of other state and federal agencies and local governments;

(8) any feasible combination of energy conservation improvements, required under section 216B.241, that can (i) replace part or all of the energy to be provided by the proposed facility, and (ii) compete with it economically;

(9) with respect to a high-voltage transmission line, the benefits of enhanced regional reliability, access, or deliverability to the extent these factors improve the robustness of the transmission system or lower costs for electric consumers in Minnesota;

(10) whether the applicant or applicants are in compliance with applicable provisions of sections 216B.1691 and 216B.2425, subdivision 7, and have filed or will file by a date certain an application for certificate of need under this section or for certification as a priority electric transmission project under section 216B.2425 for any transmission facilities or upgrades identified under section 216B.2425, subdivision 7;

(11) whether the applicant has made the demonstrations required under subdivision 3a; and

(12) if the applicant is proposing a nonrenewable generating plant, the applicant's assessment of the risk of environmental costs and regulation on that proposed facility over the expected useful life of the plant, including a proposed means of allocating costs associated with that risk.

Subd. 3a.Use of renewable resource.

The commission may not issue a certificate of need under this section for a large energy facility that generates electric power by means of a nonrenewable energy source, or that transmits electric power generated by means of a nonrenewable energy source, unless the applicant for the certificate has demonstrated to the commission's satisfaction that it has explored the possibility of generating power by means of renewable energy sources and has demonstrated that the alternative selected is less expensive (including environmental costs) than power generated by a renewable energy source. For purposes of this subdivision, "renewable energy source" includes hydro, wind, solar, and geothermal energy and the use of trees or other vegetation as fuel.

Subd. 3b.Nuclear power plant; new construction prohibited; relicensing.

(a) The commission may not issue a certificate of need for the construction of a new nuclear-powered electric generating plant.

(b) Any certificate of need for additional storage of spent nuclear fuel for a facility seeking a license extension shall address the impacts of continued operations over the period for which approval is sought.

Subd. 4.Application for certificate; hearing.

Any person proposing to construct a large energy facility shall apply for a certificate of need and for a site or route permit under chapter 216E prior to construction of the facility. The application shall be on forms and in a manner established by the commission. In reviewing each application the commission shall hold at least one public hearing pursuant to chapter 14. The public hearing shall be held at a location and hour reasonably calculated to be convenient for the public. An objective of the public hearing shall be to obtain public opinion on the necessity of granting a certificate of need and, if a joint hearing is held, a site or route permit. The commission shall designate a commission employee whose duty shall be to facilitate citizen participation in the hearing process. Unless the commission determines that a joint hearing on siting and need under this subdivision and section 216E.03, subdivision 6, is not feasible or more efficient, or otherwise not in the public interest, a joint hearing under those subdivisions shall be held.

Subd. 5.Approval, denial, or modification.

Within 12 months of the submission of an application, the commission shall approve or deny a certificate of need for the facility. Approval or denial of the certificate shall be accompanied by a statement of the reasons for the decision. Issuance of the certificate may be made contingent upon modifications required by the commission. If the commission has not issued an order on the application within the 12 months provided, the commission may extend the time period upon receiving the consent of the parties or on its own motion, for good cause, by issuing an order explaining the good cause justification for extension.

Subd. 6.Application fees; rules.

Any application for a certificate of need shall be accompanied by the application fee required pursuant to this subdivision. The application fee is to be applied toward the total costs reasonably necessary to complete the evaluation of need for the proposed facility. The maximum application fee shall be $50,000, except for an application for an electric power generating plant as defined in section 216B.2421, subdivision 2, clause (1), or a high-voltage transmission line as defined in section 216B.2421, subdivision 2, clause (2), for which the maximum application fee shall be $100,000. Costs exceeding the application fee and reasonably necessary to complete the evaluation of need for the proposed facility shall be recovered from the applicant. If the applicant is a public utility, a cooperative electric association, a generation and transmission cooperative electric association, a municipal power agency, a municipal electric utility, or a transmission company, the recovery shall be done pursuant to section 216B.62. The commission shall establish by rule pursuant to chapter 14 and sections 216C.05 to 216C.30 and this section, a schedule of fees based on the output or capacity of the facility and the difficulty of assessment of need. Money collected in this manner shall be credited to the general fund of the state treasury.

Subd. 7.Participation by other agency or political subdivision.

(a) Other state agencies authorized to issue permits for siting, construction or operation of large energy facilities, and those state agencies authorized to participate in matters before the commission involving utility rates and adequacy of utility services, shall present their position regarding need and participate in the public hearing process prior to the issuance or denial of a certificate of need. Issuance or denial of certificates of need shall be the sole and exclusive prerogative of the commission and these determinations and certificates shall be binding upon other state departments and agencies, regional, county, and local governments and special purpose government districts except as provided in sections 116C.01 to 116C.08 and 116D.04, subdivision 9.

(b) An applicant for a certificate of need shall notify the commissioner of agriculture if the proposed project will impact cultivated agricultural land, as that term is defined in section 216G.01, subdivision 4. The commissioner may participate in any proceeding on the application and advise the commission as to whether to grant the certificate of need, and the best options for mitigating adverse impacts to agricultural lands if the certificate is granted. The Department of Agriculture shall be the lead agency on the development of any agricultural mitigation plan required for the project.

Subd. 8.Exemptions.

This section does not apply to:

(1) cogeneration or small power production facilities as defined in the Federal Power Act, United States Code, title 16, section 796, paragraph (17), subparagraph (A), and paragraph (18), subparagraph (A), and having a combined capacity at a single site of less than 80,000 kilowatts; plants or facilities for the production of ethanol or fuel alcohol; or any case where the commission has determined after being advised by the attorney general that its application has been preempted by federal law;

(2) a high-voltage transmission line proposed primarily to distribute electricity to serve the demand of a single customer at a single location, unless the applicant opts to request that the commission determine need under this section or section 216B.2425;

(3) the upgrade to a higher voltage of an existing transmission line that serves the demand of a single customer that primarily uses existing rights-of-way, unless the applicant opts to request that the commission determine need under this section or section 216B.2425;

(4) a high-voltage transmission line of one mile or less required to connect a new or upgraded substation to an existing, new, or upgraded high-voltage transmission line;

(5) conversion of the fuel source of an existing electric generating plant to using natural gas; or

(6) the modification of an existing electric generating plant to increase efficiency, as long as the capacity of the plant is not increased more than ten percent or more than 100 megawatts, whichever is greater.

Subd. 9.Renewable energy standard facilities.

This section does not apply to a wind energy conversion system or a solar electric generation facility that is intended to be used to meet the obligations of section 216B.1691; provided that, after notice and comment, the commission determines that the facility is a reasonable and prudent approach to meeting a utility's obligations under that section. When making this determination, the commission must consider:

(1) the size of the facility relative to a utility's total need for renewable resources;

(2) alternative approaches for supplying the renewable energy to be supplied by the proposed facility;

(3) the facility's ability to promote economic development, as required under section 216B.1691, subdivision 9;

(4) the facility's ability to maintain electric system reliability;

(5) impacts on ratepayers; and

(6) other criteria as the commission may determine are relevant.


MISCELLANY

216B.244 NUCLEAR PLANT CAPACITY REQUIREMENTS.

A reactor unit at a nuclear power electric generating plant that has an annual load capacity factor of less than 55 percent for each of three consecutive calendar years must be shut down and cease operating no later than 500 days after the end of the third such consecutive calendar year. For the purposes of this section, "load capacity factor" means the ratio between a reactor unit's average load and its peak load.

216B.2445 DECOMMISSIONING NUCLEAR PLANT; STORING USED FUEL.

Subdivision 1.Decommissioning costs.

(a) The Public Utilities Commission shall, when considering approval of a plan for the accrual of funds for the decommissioning of nuclear facilities filed in accordance with a commission order, include an evaluation of the costs, if any, arising from storage of used nuclear fuel that may be incurred by the state of Minnesota, and any tribal community, county, city, or township where used nuclear fuel is located following the cessation of operations at a nuclear plant.

(b) To assist the commission in making the determination required in paragraph (a), the filing shall provide cost estimates, including ratepayer impacts, assuming used nuclear fuel will be stored in the state for 60 years, 100 years, and 200 years following the cessation of operation of the nuclear plant.

Subd. 2.Rate.

A public utility filing a decommissioning plan in accordance with a commission order and this section may include, as part of a general rate case petition, the costs of decommissioning accrual incurred in complying with a commission order implementing this section.

Subd. 3.Commission report.

The commission shall prepare a nuclear decommissioning report after each of the commission's periodic review of nuclear decommissioning costs. The report shall be submitted within 180 days of the date of the final order related to that review to the chairs and ranking minority members of the legislative committees with primary jurisdiction over energy policy and public safety. That report shall, without limitation, include the following:

(1) an explanation of the commission's funding decisions regarding nuclear decommissioning;

(2) the progress of the United States Department of Energy to remove from Minnesota spent fuel produced by nuclear generating plants in Minnesota;

(3) an analysis of the financial and other obligations related to decommissioning and storage of used fuel of the utility holding title to spent nuclear fuel to the state and to host communities, including affected tribal communities; and

(4) any recommendations to the legislature on legislation or other actions that may be necessary for addressing long-term or indefinite storage costs.

History:

2011 c 97 s 13

216B.245 PUMP AND STORE HYDROPOWER FACILITY; PROHIBITION.

A state agency may not issue a permit for the construction of a facility for generating electricity if the facility would be located on top of the bluffs along the Mississippi River and would pump water from any portion of the river, store the water on top of the bluffs, and release the water at a later time to generate the electricity.

History:

1993 c 147 s 1

216B.246 FEDERALLY APPROVED TRANSMISSION LINES; INCUMBENT TRANSMISSION LINEOWNER RIGHTS.

Subdivision 1.Definitions.

(a) For purposes of this section, the terms defined in this subdivision have the meanings given them.

(b) "Electric transmission line" means a high-voltage transmission line with a capacity of 100 kilovolts or more and associated transmission facilities.

(c) "Incumbent electric transmission owner" means any public utility that owns, operates, and maintains an electric transmission line in this state; any generation and transmission cooperative electric association; any municipal power agency; any power district; any municipal utility; or any transmission company as defined under section 216B.02, subdivision 10.

Subd. 2.Incumbent electric transmission owner rights.

An incumbent electric transmission owner has the right to construct, own, and maintain an electric transmission line that has been approved for construction in a federally registered planning authority transmission plan and connects to facilities owned by that incumbent electric transmission owner. The right to construct, own, and maintain an electric transmission line that connects to facilities owned by two or more incumbent electric transmission owners belongs individually and proportionally to each incumbent electric transmission owner, unless otherwise agreed upon in writing. This section does not limit the right of any incumbent electric transmission owner to construct, own, and maintain any transmission equipment or facilities that have a capacity of less than 100 kilovolts.

Subd. 3.Commission procedure.

(a) If an electric transmission line has been approved for construction in a federally registered planning authority transmission plan, the incumbent electric transmission owner, or owners if there is more than one owner, shall give notice to the commission, in writing, within 90 days of approval, regarding its intent to construct, own, and maintain the electric transmission line. If an incumbent electric transmission owner gives notice of intent to build the electric transmission line then, unless exempt from the requirements of section 216B.243, within 18 months from the date of the notice described in this paragraph or such longer time approved by the commission, the incumbent electric transmission owner shall file an application for a certificate of need under section 216B.243 or certification under section 216B.2425.

(b) If the incumbent electric transmission owner indicates that it does not intend to build the transmission line, such notice shall fully explain the basis for that decision. If the incumbent electric transmission owner, or owners, gives notice of intent not to build the electric transmission line, then the commission may determine whether the incumbent electric transmission owner or other entity will build the electric transmission line, taking into consideration issues such as cost, efficiency, reliability, and other factors identified in this chapter.

History:

2012 c 179 s 1


COMMISSION ORDERS; PROCEDURAL RESPONSIBILITIES

216B.25 FURTHER ACTION ON PREVIOUS ORDER.

The commission may at any time, on its own motion or upon motion of an interested party, and upon notice to the public utility and after opportunity to be heard, rescind, alter, or amend any order fixing rates, tolls, charges, or schedules, or any other order made by the commission, and may reopen any case following the issuance of an order therein, for the taking of further evidence or for any other reason. Any order rescinding, altering, amending, or reopening a prior order shall have the same effect as an original order.

History:

1974 c 429 s 25

216B.26 ORDER; EFFECTIVE DATE.

Every decision made by the commission constituting an order or determination is in force and effective 20 days after it has been filed and has been served by personal delivery, electronic service as provided in section 216.17, or by mailing a copy thereof to all parties to the proceeding in which the decision was made or to their attorneys, unless the commission specifies a different date upon which the order becomes effective.

216B.27 REHEARING; CONDITION PRECEDENT TO JUDICIAL REVIEW.

Subdivision 1.Applying for rehearing.

Within 20 days after the service by the commission of any decision constituting an order or determination, any party to the proceeding and any other person, aggrieved by the decision and directly affected thereby, may apply to the commission for a rehearing in respect to any matters determined in the decision. The commission may grant and hold a rehearing on the matters, or upon any of them as it may specify in the order granting the rehearing, if in its judgment sufficient reason therefor exists.

Subd. 2.Contents of application; condition precedent for review.

The application for a rehearing shall set forth specifically the grounds on which the applicant contends the decision is unlawful or unreasonable. No cause of action arising out of any decision constituting an order or determination of the commission or any proceeding for the judicial review thereof shall accrue in any court to any person or corporation unless the plaintiff or petitioner in the action or proceeding within 20 days after the service of the decision, shall have made application to the commission for a rehearing in the proceeding in which the decision was made. No person or corporation shall in any court urge or rely on any ground not so set forth in the application for rehearing.

Subd. 3.Rules; procedural requirements; commission's authority.

Applications for rehearing shall be governed by general rules which the commission may establish. In case a rehearing is granted the proceedings shall conform as nearly as may be to the proceedings in an original hearing, except as the commission may otherwise direct. If in the commission's judgment, after the rehearing, it shall appear that the original decision, order, or determination is in any respect unlawful or unreasonable, the commission may reverse, change, modify, or suspend the original action accordingly. Any decision, order, or determination made after the rehearing reversing, changing, modifying, or suspending the original determination shall have the same force and effect as an original decision, order, or determination. Only one rehearing shall be granted by the commission; but this shall not be construed to prevent any party from filing a new application or complaint. No order of the commission shall become effective while an application for a rehearing or a rehearing is pending and until ten days after the application for a rehearing is either denied, expressly or by implication, or the commission has announced its final determination on rehearing.

Subd. 4.Deadline to grant application.

Any application for a rehearing not granted within 60 days from the date of filing thereof, shall be deemed denied.

Subd. 5.Effect of decision on application.

It is hereby declared that the legislative powers of the state, insofar as they are involved in the issuance of orders and decisions by the commission, have not been completely exercised until the commission has acted upon an application for rehearing, as provided for by this section and by the rules of the commission, or until the application for rehearing has been denied by implication, as above provided for.

216B.28 SUBPOENA; WITNESS FEE AND MILEAGE.

The commission and each commissioner, or the secretary of the commission may issue subpoenas and all necessary processes in proceedings pending before it; and each process shall extend to all parts of the state and may be served by any person authorized to serve processes of courts of record. Each witness who shall appear before the commission, or at a hearing before one of the individuals designated by it as provided in section 216B.15, or whose deposition is taken, shall receive for attendance the fees and mileage now provided for witnesses in civil cases in courts of record.

History:

1974 c 429 s 28; 1986 c 444

216B.29 HEARING AND SUBPOENA COMPLIANCE POWERS.

The commission and each of the commissioners or authorized examiner, for the purpose mentioned in Laws 1974, chapter 429, may administer oaths and examine witnesses. In case of failure on the part of any person to comply with any subpoena, or in the case of the refusal of any witness to testify concerning any matter on which the witness may be interrogated lawfully, any court of record of general jurisdiction or a judge thereof, on application of the commission, may compel obedience by proceedings for contempt as in the case of disobedience of the requirements of a subpoena issued from the court or a refusal to testify therein.

History:

1974 c 429 s 29; 1986 c 444

216B.30 DEPOSITION.

The commission or any party to the proceedings may, in any investigation or hearing before the commission, cause the deposition of witnesses residing within or without the state to be taken in the manner prescribed by law for taking depositions in civil actions in the district court.

History:

1974 c 429 s 30

216B.31 TESTIMONY AND PRODUCTION OF RECORDS; PERJURY.

No person shall be excused from testifying or from producing any book, document, paper, or account in any investigation, or inquiry by, or hearing before, the commission or any commissioner, or person designated by it to conduct hearings, when ordered to do so, upon the ground that the testimony or evidence, book, document, paper, or account required may tend to incriminate the person or subject the person to penalty or forfeiture; but no person shall be prosecuted, punished, or subjected to any forfeiture or penalty for or on account of any act, transaction, matter, or thing concerning which the person shall have been compelled under oath to testify or produce documentary evidence; provided, that no person so testifying shall be exempt from prosecution or punishment for any perjury committed in testimony.

History:

1974 c 429 s 31; 1986 c 444

216B.32 CERTIFIED COPY OF DOCUMENT AS EVIDENCE.

Copies of official documents and orders filed or deposited according to law in the office of the commission, certified by a commissioner or by the secretary under the official seal of the commission to be true copies of the original shall be evidence in like manner as the originals, in all matters before the commission and in the courts of this state.

History:

1974 c 429 s 32

216B.33 COMMISSION RULING WRITTEN, FILED, AND CERTIFIED.

Every order, finding, authorization, or certificate issued or approved by the commission under this chapter must be in writing and retained in the commission's official record system. A certificate under the seal of the commission that any order, finding, authorization, or certificate has not been modified, stayed, suspended, or revoked, must be received in any proceeding as evidence as to the facts therein stated.

216B.34 PUBLIC RECORDS.

All decisions, transcripts, and orders of the commission shall be public records.

History:

1974 c 429 s 34

216B.35 TRANSCRIBED RECORD.

A full and complete record shall be kept of all proceedings at any formal hearing had before the commission or any commissioner or hearing examiner and all testimony shall be taken down by a reporter appointed by the commission. A copy of the transcript shall be furnished on demand to any party to the proceedings upon payment of reasonable costs of reproduction.

History:

1974 c 429 s 35


MUNICIPAL POWERS

216B.36 MUNICIPAL REGULATORY AND TAXING POWERS.

Any public utility furnishing the utility services enumerated in section 216B.02 or occupying streets, highways, or other public property within a municipality may be required to obtain a license, permit, right, or franchise in accordance with the terms, conditions, and limitations of regulatory acts of the municipality, including the placing of distribution lines and facilities underground. Under the license, permit, right, or franchise, the utility may be obligated by any municipality to pay to the municipality fees to raise revenue or defray increased municipal costs accruing as a result of utility operations, or both. The fee may include but is not limited to a sum of money based upon gross operating revenues or gross earnings from its operations in the municipality so long as the public utility shall continue to operate in the municipality, unless upon request of the public utility it is expressly released from the obligation at any time by such municipality. Notwithstanding the definition of "public utility" in section 216B.02, subdivision 4, a municipality may require payment of a fee under this section by a cooperative electric association organized under chapter 308A that furnishes utility services within the municipality. All existing licenses, permits, franchises, and other rights acquired by any public utility or municipality prior to April 11, 1974, including the payment of existing franchise fees, shall not be impaired or affected in any respect by the passage of this chapter, except with respect to matters of rate and service regulation, service area assignments, securities, and indebtedness that are vested in the jurisdiction of the commission by this chapter. However, in the event that a court of competent jurisdiction determines, or the parties by mutual agreement determine, that an existing license, permit, franchise, or other right has been abrogated or impaired by this chapter, or its execution, the municipality affected shall impose and the public utility shall collect an excise tax on the utility charges which from year to year yields an amount which is reasonably equivalent to that amount of revenue which then would be due as a fee, charges or other thing or service of value to the municipality under the franchise, license, or permit. The authorization shall be over and above taxing limitations including, but not limited to, those of section 477A.016. Franchises granted pursuant to this section shall be exempt from the provisions of chapter 80C. For purposes of this section, a public utility shall include a cooperative electric association.


TOWNSHIP NATURAL GAS UTILITY AGREEMENT

216B.361 TOWNSHIP AGREEMENT WITH NATURAL GAS UTILITY.

A township may enter into an agreement with a public utility providing natural gas services to provide services within a designated portion or all of the township. If a city annexes township land for which a utility has an agreement with a township to serve, the utility shall continue to have a nonexclusive right to offer and provide service in the area identified by the agreement with the township for the term of that agreement, subject to the authority of the annexing city to manage public rights-of-way within the city as provided in sections 216B.36, 237.162, and 237.163.

Nothing in this section precludes a city from acquiring the property of a public utility under sections 216B.45 to 216B.47 for the purpose of allowing the city to own and operate a natural gas utility, or to extend natural gas and other utility services into newly annexed areas.


ASSIGNED ELECTRIC SERVICE AREAS

216B.37 ASSIGNED SERVICE AREA; ELECTRIC UTILITY; LEGISLATIVE POLICY.

It is hereby declared to be in the public interest that, in order to encourage the development of coordinated statewide electric service at retail, to eliminate or avoid unnecessary duplication of electric utility facilities, and to promote economical, efficient, and adequate electric service to the public, the state of Minnesota shall be divided into geographic service areas within which a specified electric utility shall provide electric service to customers on an exclusive basis.

History:

1974 c 429 s 37

216B.38 DEFINITIONS.

Subdivision 1.

MS 1974 [Renumbered subd 1a]

Subdivision 1.Scope.

For the purpose of sections 216B.37 to 216B.44 only, the following definitions shall apply.

Subd. 1a.

[Renumbered subd 8]

Subd. 1b.Assigned service area.

"Assigned service area" means the geographical area in which the boundaries are established as provided in section 216B.39.

Subd. 2.Customer.

"Customer" means a person contracting for or purchasing electric service at retail from an electric utility.

Subd. 3.

[Renumbered subd 4a]

Subd. 4.Electric line.

"Electric line" means lines for conducting electric energy at a design voltage of 25,000 volts phase to phase or less used for distributing electric energy directly to customers at retail.

Subd. 4a.Electric service.

"Electric service" means electric service furnished to a customer at retail for ultimate consumption, but does not include wholesale electric energy furnished by an electric utility to another electric utility for resale.

Subd. 5.Electric utility.

"Electric utility" means persons, their lessees, trustees, and receivers, separately or jointly, now or hereafter operating, maintaining, or controlling in Minnesota equipment or facilities for providing electric service at retail and which fall within the definition of "public utility" in section 216B.02, subdivision 4, and includes facilities owned by a municipality or by a cooperative electric association.

Subd. 6.

[Renumbered subd 1b]

Subd. 7.Municipality.

"Municipality" means any city, however organized.

Subd. 8.Person.

"Person" means a natural person, a partnership, a private corporation, a public corporation, a municipality, an association, a cooperative whether incorporated or not, a joint stock association, a business trust, any political subdivision or agency, or two or more persons having joint or common interest.

216B.39 ASSIGNED SERVICE AREA.

Subdivision 1.Line map and service list.

On or before six months from April 12, 1974, or, when requested in writing by an electric utility and for good cause shown, and at a further time as the commission may fix by order, each electric utility shall file with the commission a map or maps showing all its electric lines outside of incorporated municipalities as they existed on April 12, 1974. Each electric utility shall also submit in writing a list of all municipalities in which it provides electric service on the effective date of Laws 1974, chapter 429. Where two or more electric utilities serve a single municipality, the commission may require each utility to file with the commission a map showing its electric lines within the municipality.

Subd. 2.Determination; map prepared.

On or before 12 months from April 12, 1974, the commission shall after notice and hearing establish the assigned service area or areas of each electric utility and shall prepare or cause to be prepared a map or maps to accurately and clearly show the boundaries of the assigned service area of each electric utility.

Subd. 3.Geographic, historic, and contractual considerations.

To the extent that it is not inconsistent with the legislative policy stated in section 216B.37, the boundaries of each assigned service area, outside of incorporated municipalities, shall be a line equidistant between the electric lines of adjacent electric utilities as they exist on April 12, 1974; provided that these boundaries may be modified by the commission to take account of natural and other physical barriers including, but not limited to, highways, waterways, railways, major bluffs, and ravines and shall be modified to take account of the contracts provided for in subdivision 4; and provided further that at any time after April 12, 1974, the commission may on its own or at the request of an electric utility make changes in the boundaries of the assigned service areas, but only after notice and hearing as provided for in sections 216B.17 and 216B.18.

Subd. 4.Service area contract between utilities.

Contracts between electric utilities, which are executed on or before 12 months from April 12, 1974, designating service areas and customers to be served by the electric utilities when approved by the commission shall be valid and enforceable and shall be incorporated into the appropriate assigned service areas. The commission shall approve a contract if it finds that the contract will eliminate or avoid unnecessary duplication of facilities, will provide adequate electric service to all areas and customers affected, and will promote the efficient and economical use and development of the electric systems of the contracting electric utilities.

Subd. 5.Assigned service area in municipality.

Where a single electric utility provides electric service within a municipality on April 12, 1974, that entire municipality shall constitute a part of the assigned service area of the electric utility in question. Where two or more electric utilities provide electric service in a municipality on April 12, 1974, the boundaries of the assigned service areas shall conform to those contained in municipal franchises with the electric utilities on April 12, 1974. In the absence of a franchise, the boundaries of the assigned service areas within an incorporated municipality shall be a line equidistant between the electric lines of the electric utilities as they exist on April 12, 1974; provided that these boundaries may be modified by the commission to take account of natural and other physical barriers including, but not limited to, major streets or highways, waterways, railways, major bluffs, and ravines and shall be modified to take account of the contracts provided for in subdivision 4.

Subd. 6.Determination for exceptional case.

In those areas where, on April 12, 1974, the existing electric lines of two or more electric utilities are so intertwined that subdivisions 2 to 5 cannot reasonably be applied, the commission shall determine the boundaries of the assigned service areas for the electric utilities involved as will promote the legislative policy in section 216B.37, subdivision 1.

History:

1974 c 429 s 39

216B.40 EXCLUSIVE SERVICE RIGHT; SERVICE EXTENSION.

Except as provided in sections 216B.42 and 216B.421, each electric utility shall have the exclusive right to provide electric service at retail to each and every present and future customer in its assigned service area and no electric utility shall render or extend electric service at retail within the assigned service area of another electric utility unless the electric utility consents thereto in writing; provided that any electric utility may extend its facilities through the assigned service area of another electric utility if the extension is necessary to facilitate the electric utility connecting its facilities or customers within its own assigned service area.

216B.41 EFFECT OF INCORPORATION, ANNEXATION, OR CONSOLIDATION.

After April 12, 1974, the inclusion by incorporation, consolidation, or annexation of any part of the assigned service area of an electric utility within the boundaries of any municipality shall not in any respect impair or affect the rights of the electric utility to continue and extend electric service at retail throughout any part of its assigned service area unless a municipality which owns and operates an electric utility elects to purchase the facilities and property of the electric utility as provided in section 216B.44.

History:

1974 c 429 s 41

216B.42 SERVICE EXTENSION IN CERTAIN SITUATIONS.

Subdivision 1.Large customer outside municipality.

Notwithstanding the establishment of assigned service areas for electric utilities provided for in section 216B.39, customers located outside municipalities and who require electric service with a connected load of 2,000 kilowatts or more shall not be obligated to take electric service from the electric utility having the assigned service area where the customer is located if, after notice and hearing, the commission so determines after consideration of following factors:

(1) the electric service requirements of the load to be served;

(2) the availability of an adequate power supply;

(3) the development or improvement of the electric system of the utility seeking to provide the electric service, including the economic factors relating thereto;

(4) the proximity of adequate facilities from which electric service of the type required may be delivered;

(5) the preference of the customer;

(6) any and all pertinent factors affecting the ability of the utility to furnish adequate electric service to fulfill customers' requirements.

Subd. 2.Service line extension to utility's property.

Notwithstanding the provisions in section 216B.39, any electric utility may extend electric lines for electric service to its own utility property and facilities.

History:

1974 c 429 s 42

216B.421 HOMESTEAD; OPTION OF ELECTRIC SERVICE.

Subdivision 1.Multiple service areas; customer election.

Notwithstanding the establishment of assigned service areas for electric utilities provided for in section 216B.39, when a customer requires electric service for buildings or other structures located on land constituting the customer's homestead and the buildings or structures are located within more than one assigned service area, the customer may elect to contract for or purchase the customer's entire electric service requirements from either of the electric utilities providing the customer with electric service. An electric utility may extend its facilities through the assigned service area of another electric utility if the extension is necessary to facilitate the electric utility connecting a customer who elects to purchase or contract for service from it pursuant to this section.

Subd. 2.Restriction.

The provisions of subdivision 1 shall only apply to the provision of electric service to buildings and other structures that were under construction on April 11, 1974.

History:

1977 c 99 s 2; 1986 c 444

216B.43 HEARING ON COMPLAINT.

Upon the filing of an application under section 216B.42 or upon complaint by an affected utility that the provisions of sections 216B.39 to 216B.42 have been violated, the commission shall hold a hearing, upon notice, within 30 days after the filing of the complaint, and shall render its decision within 30 days after the hearing.


MUNICIPAL ACQUISITION OF UTILITY PROPERTY

216B.44 MUNICIPAL SERVICE TERRITORY EXTENSION.

(a) Notwithstanding the provisions of sections 216B.38 to 216B.42, whenever a municipality which owns and operates an electric utility (1) extends its corporate boundaries through annexation or consolidation, or (2) determines to extend its service territory within its existing corporate boundaries, the municipality shall thereafter furnish electric service to these areas unless the area is already receiving electric service from an electric utility, in which event, the municipality may purchase the facilities of the electric utility serving the area.

(b) The municipality acquiring the facilities shall pay to the electric utility formerly serving the area the appropriate value of its properties within the area which payment may be by exchange of other electric utility property outside the municipality on an appropriate basis giving due consideration to revenue from and value of the respective properties. In the event the municipality and the electric utility involved are unable to agree as to the terms of the payment or exchange, the municipality or the electric utility may file an application with the commission requesting that the commission determine the appropriate terms for the exchange or sale. After notice and hearing, the commission shall determine appropriate terms for an exchange, or in the event no appropriate properties can be exchanged, the commission shall fix and determine the appropriate value of the property within the annexed area, and the transfer shall be made as directed by the commission. In making that determination the commission shall consider the original cost of the property, less depreciation, loss of revenue to the utility formerly serving the area, expenses resulting from integration of facilities, and other appropriate factors.

(c) Until the determination by the commission, the facilities shall remain in place and service to the public shall be maintained by the owner. However, the electric utility being displaced, serving the annexed area, shall not extend service to any additional points of delivery within the annexed area if the commission, after notice and hearing, with due consideration of any unnecessary duplication of facilities, shall determine that the extension is not in the public interest.

(d) When property of an electric utility located within an area annexed to a municipality which owns and operates an electric utility is proposed to be acquired by the municipality, ratification by the electors is not required.

(e) When property of an electric utility located within the existing corporate boundaries of a municipality that currently operates a municipal electric utility is proposed to be included within the service territory of the municipal electric utility, ratification by the electors is not required.

216B.45 MUNICIPAL PURCHASE OF PUBLIC UTILITY.

Any public utility operating in a municipality under a license, permit, right, or franchise shall be deemed to have consented to the purchase by the municipality, for just compensation, of its property operated in the municipality under such license, permit, right, or franchise. The municipality, subject to the provisions of Laws 1974, chapter 429, may purchase the property upon notice to the public utility as herein provided. Whenever the commission is notified by the municipality or the public utility affected that the municipality has, pursuant to law, determined to purchase the property of the public utility, and that the parties to the purchase and sale have been unable to agree on the amount to be paid and received therefor, the commission shall set a time and place for a public hearing, after not less than 30 days' notice to the parties, upon the matter of just compensation or the matter of the property to be purchased. Within a reasonable time the commission shall, by order, determine the just compensation for the property to be purchased by the municipality. In determining just compensation, the commission shall consider the original cost of the property less depreciation, loss of revenue to the utility, expenses resulting from integration of facilities, and other appropriate factors. The order of the commission may be reviewed as provided in section 216B.52. Commission expenses arising out of the exercise of its jurisdiction under this section shall be assessed to the municipality. For purposes of this section, a public utility shall include a cooperative electric association.

216B.46 MUNICIPAL ACQUISITION PROCEDURES; NOTICE; ELECTION.

Any municipality which desires to acquire the property of a public utility as authorized under the provisions of section 216B.45 may determine to do so by resolution of the governing body of the municipality taken after a public hearing of which at least 30 days' published notice shall be given as determined by the governing body. The determination shall become effective when ratified by a majority of the qualified electors voting on the question at a special election to be held for that purpose, not less than 60 nor more than 120 days after the resolution of the governing body of the municipality.

History:

1974 c 429 s 46

216B.465 VOTER RATIFICATION OF MUNICIPAL PURCHASE, LIMITED APPLICATION.

The provisions of sections 216B.45 and 216B.46 apply only to the purchase of public utility property by a municipality that, prior to the time of the purchase, did not operate a municipal utility providing the type of utility service delivered by the utility property being purchased.

In cases where the municipality operates, prior to the purchase of public utility property, a municipal utility providing the type of utility service delivered by the utility property being purchased, the provisions of section 216B.44 apply and voter ratification is not required.

History:

1983 c 301 s 174

216B.47 ACQUISITION BY EMINENT DOMAIN.

Nothing in this chapter may be construed to preclude a municipality from acquiring the property of a public utility by eminent domain proceedings; provided that damages to be paid in eminent domain proceedings must include the original cost of the property less depreciation, loss of revenue to the utility, expenses resulting from integration of facilities, and other appropriate factors. A municipality seeking to acquire the property of a public utility in eminent domain proceedings may not acquire the right to furnish electric service during the pendency of the proceedings through the use of section 117.042 but may petition the commission under section 216B.44 for service rights. For purposes of this section, a public utility includes a cooperative electric association.


FINANCIAL ACTIVITIES AND BUSINESS PRACTICES

216B.48 RELATIONS WITH AFFILIATED INTEREST.

Subdivision 1.Definition of affiliated interests.

"Affiliated interests" with a public utility means the following:

(1) every corporation and person owning or holding directly or indirectly five percent or more of the voting securities of such public utility;

(2) every corporation and person in any chain of successive ownership of five percent or more of voting securities;

(3) every corporation five percent or more of whose voting securities is owned by any person or corporation owning five percent or more of the voting securities of such public utility or by any person or corporation in any such chain of successive ownership of five percent or more of voting securities;

(4) every person who is an officer or director of such public utility or of any corporation in any chain of successive ownership of five percent or more of voting securities;

(5) every corporation operating a public utility or a servicing organization for furnishing supervisory, construction, engineering, accounting, legal, and similar services to utilities, which has one or more officers or one or more directors in common with the public utility, and every other corporation which has directors in common with the public utility where the number of the directors is more than one-third of the total number of the utility's directors;

(6) every corporation or person which the commission may determine as a matter of fact after investigation and hearing is actually exercising any substantial influence over the policies and actions of the public utility even though the influence is not based upon stockholding, stockholders, directors or officers to the extent specified in this section;

(7) every person or corporation who or which the commission may determine as a matter of fact after investigation and hearing is actually exercising substantial influence over the policies and actions of the public utility in conjunction with one or more other corporations or persons with which or whom they are related by ownership or blood relationship or by action in concert that together they are affiliated with such public utility within the meaning of this section even though no one of them alone is so affiliated;

(8) every subsidiary of a public utility;

(9) every part of a corporation in which an operating division is a public utility.

Subd. 2.Construing the term "person."

The term "person" as used in subdivision 1 shall not be construed to exclude trustees, lessees, holders of beneficial equitable interest, voluntary associations, receivers, and partnerships.

Subd. 3.Contract between utility and affiliated interest.

No contract or arrangement, including any general or continuing arrangement, providing for the furnishing of management, supervisory, construction, engineering, accounting, legal, financial, or similar services, and no contract or arrangement for the purchase, sale, lease, or exchange of any property, right, or thing, or for the furnishing of any service, property, right, or thing, other than those above enumerated, made or entered into after January 1, 1975 between a public utility and any affiliated interest as defined in subdivision 1, clauses (1) to (8), or any arrangement between a public utility and an affiliated interest as defined in subdivision 1, clause (9), made or entered into after August 1, 1993, is valid or effective unless and until the contract or arrangement has received the written approval of the commission. Regular recurring transactions under a general or continuing arrangement that has been approved by the commission are valid if they are conducted in accordance with the approved terms and conditions. Every public utility shall file with the commission a verified copy of the contract or arrangement, or a verified summary of the unwritten contract or arrangement, and also of all the contracts and arrangements, whether written or unwritten, entered into prior to January 1, 1975, or, for the purposes of subdivision 1, clause (9), prior to August 1, 1993, and in force and effect at that time. The commission shall approve the contract or arrangement made or entered into after that date only if it clearly appears and is established upon investigation that it is reasonable and consistent with the public interest. No contract or arrangement may receive the commission's approval unless satisfactory proof is submitted to the commission of the cost to the affiliated interest of rendering the services or of furnishing the property or service to each public utility. Proof is satisfactory only if it includes the original or verified copies of the relevant cost records and other relevant accounts of the affiliated interest, or an abstract or summary as the commission may deem adequate, properly identified and duly authenticated, provided, however, that the commission may, where reasonable, approve or disapprove the contracts or arrangements without the submission of cost records or accounts. The burden of proof to establish the reasonableness of the contract or arrangement is on the public utility.

Subd. 4.Contract not exceeding $50,000.

The provisions of this section requiring the written approval of the commission shall not apply to transactions with affiliated interests where the amount of consideration involved is not in excess of $50,000 or five percent of the capital equity of the utility whichever is smaller; provided, however, that regularly recurring payments under a general or continuing arrangement which aggregate a greater annual amount shall not be broken down into a series of transactions to come within the aforesaid exemption. Such transactions shall be valid or effective without commission approval under this section. However, in any proceeding involving the rates or practices of the public utility, the commission may exclude from the accounts of such public utility any payment or compensation made pursuant to the transaction unless the public utility shall establish the reasonableness of the payment or compensation.

Subd. 5.Applicability to determining rates and costs.

In any proceeding, whether upon the commission's own motion or upon application or complaint, involving the rates or practices of any public utility, the commission may exclude from the accounts of the public utility any payment or compensation to an affiliated interest for any services rendered or property or service furnished, as above described, under existing contracts or arrangements with the affiliated interest unless the public utility shall establish the reasonableness of the payment or compensation.

Subd. 6.Commission retains continuing authority over contract.

The commission shall have continuing supervisory control over the terms and conditions of the contracts and arrangements as are herein described so far as necessary to protect and promote the public interest. The commission shall have the same jurisdiction over the modifications or amendment of contracts or arrangements as are herein described as it has over such original contracts or arrangements. The fact that the commission shall have approved entry into such contracts or arrangements as described herein shall not preclude disallowance or disapproval of payments made pursuant thereto, if upon actual experience under such contract or arrangement it appears that the payments provided for or made were or are unreasonable.

Subd. 7.

[Repealed, 1978 c 795 s 10]

216B.49 SECURITIES; PUBLIC FINANCING.

Subdivision 1.Definition of security.

For the purpose of this section, "security" means any note; stock; treasury stock; bond; debenture; evidence of indebtedness; assumption of any obligation or liability as a guarantor, endorser, surety, or otherwise in the security of another person; certificate of interest or participation in any profit-sharing agreement; collateral trust certificate; preorganization certificate or subscription; transferable shares; investment contract; voting trust certificate; certificate of deposit for a security; certificate of interest or participation in an oil, gas, or mining right, title, or lease or in payments out of production under an oil, gas, or mining right, title, or lease; or, in general, any interest or instrument commonly known as a security, or any certificate for, receipt for guarantee of, or warrant or right to subscribe to or purchase, any of the foregoing.

Subd. 2.

[Repealed, 1998 c 350 s 6]

Subd. 3.Commission approval required.

It is unlawful for any public utility organized under the laws of this state to offer or sell any security or, if organized under the laws of any other state or foreign country, to subject property in this state to an encumbrance for the purpose of securing the payment of any indebtedness unless the security issuance of the public utility is first approved by the commission, either as an individual issuance or as one of multiple possible issuances approved in the course of a periodic proceeding reviewing the utility's proposed sources and uses of capital funds. Approval by the commission must be by formal written order.

Subd. 4.Considerations for approval for public financing.

Upon the application of a public utility for approval of its security issuance and prior to the issuance of any security or the encumbrance of any property for the purpose of securing the payment of any indebtedness, the commission may make such inquiry or investigation, hold such hearings, and examine such witnesses, books, papers, documents, or contracts, as in its discretion it may deem necessary. Prior to approval the commission shall ascertain that the amount of securities of each class which any public utility may issue shall bear a reasonable proportion to each other and to the value of the property, due consideration being given to the nature of the business of the public utility, its credit and prospects, the possibility that the value of the property may change from time to time, the effect which the issue shall have upon the management and operation of the public utility, and other considerations which the commission as a matter of fact shall find to be relevant. If the commission shall find that the proposed security issuance is reasonable and proper and in the public interest and will not be detrimental to the interests of the consumers and patrons affected thereby, the commission shall by written order grant its permission for the proposed public financing.

Subd. 5.Applicability of other law; preemption.

The requirements of this section are in addition to any other requirements of law and, specifically, the requirements of chapter 80A, and the rules promulgated pursuant thereto. Notwithstanding any charter or ordinance to the contrary, no city shall have jurisdiction over the securities or indebtedness of a public utility.

Subd. 6.

[Repealed, 1978 c 795 s 10]

Subd. 7.Investment in municipal industrial development.

When a public utility is engaged in a project pursuant to sections 469.152 to 469.165, notwithstanding the provisions of section 469.155, funds or accounts established in connection with the project or payment of bonds issued for the project may also be invested in investments of the type authorized in section 11A.24, subdivisions 1 to 5.

216B.50 RESTRICTIONS ON PROPERTY TRANSFER AND MERGER.

Subdivision 1.Commission approval required.

No public utility shall sell, acquire, lease, or rent any plant as an operating unit or system in this state for a total consideration in excess of $100,000, or merge or consolidate with another public utility or transmission company operating in this state, without first being authorized so to do by the commission. Upon the filing of an application for the approval and consent of the commission, the commission shall investigate, with or without public hearing. The commission shall hold a public hearing, upon such notice as the commission may require. If the commission finds that the proposed action is consistent with the public interest, it shall give its consent and approval by order in writing. In reaching its determination, the commission shall take into consideration the reasonable value of the property, plant, or securities to be acquired or disposed of, or merged and consolidated.

This section does not apply to the purchase of property to replace or add to the plant of the public utility by construction.

Subd. 2.

[Repealed, 1978 c 795 s 10]

Subd. 3.Exempt from other law.

Mergers and consolidations as enumerated in subdivision 1 hereof shall be exempt from the provisions of chapter 80B.

216B.51 STOCK PURCHASE.

Subdivision 1.Stock of another utility.

No public utility shall purchase voting stock in another public utility doing business in Minnesota without first having made application to and received the consent of the commission in writing or by order.

Subd. 2.

[Repealed, 1978 c 795 s 10]

Subd. 3.Exempt from other law.

Mergers and consolidations as enumerated in subdivision 1 hereof shall be exempt from the provisions of chapter 80B.

History:

1974 c 429 s 51


VIOLATIONS, PENALTIES, JUDICIAL CONSIDERATIONS

216B.52 APPEAL.

Subdivision 1.Appeal under Administrative Procedure Act.

Any party to a proceeding before the commission or any other person, aggrieved by a decision and order and directly affected by it, may appeal from the decision and order of the commission in accordance with chapter 14.

Subd. 2.

[Repealed, 1983 c 247 s 219]

Subd. 3.

[Repealed, 1983 c 247 s 219]

Subd. 4.

[Repealed, 1983 c 247 s 219]

Subd. 5.

[Repealed, 1983 c 247 s 219]

216B.53 SUSPENSION OF COMMISSION ORDER.

The pendency of proceedings on appeal shall not of itself stay or suspend the operation of the order of the commission unless the commission so orders, but during the pendency of the proceedings the court in its discretion may stay or suspend, in whole or in part, the operation of the commission's order on terms it deems just, and in accordance with the practice of courts exercising equity jurisdiction. No stay shall be granted by the court without notice to the parties and opportunity to be heard. Any party shall have the right to secure from the court in which an appeal of an order of the commission is sought an order suspending or staying the operation of an order of the commission, pending an appeal of the order, but no commission order relating to rates or rules shall be stayed or suspended absent a finding that great or irreparable damage would otherwise result to the party seeking the stay or suspension, and any order staying or suspending a commission order shall specify the nature of the damage.

In case the order of the commission is stayed or suspended, the court shall require a bond with good and sufficient surety, conditioned that the public utility petitioning for review shall answer for all damages caused by the delay in enforcing the order of the commission, and for all compensation for whatever sums for transmission or service any person shall be compelled to pay pending review proceedings in excess of the sum the person or corporation would have been compelled to pay had the commission's order not been stayed or suspended. The court, may, in addition or in lieu of the bond require other further security for the payment of such excess damages or charges it deems proper.

216B.54 LEGAL ACTION AGAINST VIOLATION.

Whenever the commission or department shall be of the opinion that any person or public utility is failing or omitting or is about to fail or omit to do anything required of it by Laws 1974, chapter 429 or by any order of the commission, or is doing anything or about to do anything, or permitting anything or about to permit anything to be done, contrary to or in violation of Laws 1974, chapter 429 or of any order of the commission, it shall refer the matter to the attorney general who shall take appropriate legal action.

216B.55 [Repealed, 1983 c 247 s 219]

216B.56 BURDEN OF PROOF.

In all proceedings before the commission in which the modification or vacation of any order of the commission is sought, the burden of proof shall be on the person seeking such modification or vacation.

History:

1974 c 429 s 56

216B.57 PENALTY FOR VIOLATION OF ACT.

Any person who knowingly and intentionally violates any provision of Laws 1974, chapter 429, or who knowingly and intentionally fails, omits, or neglects to obey, observe, or comply with any lawful order, or any part or provision thereof, of the commission is subject to a penalty of not less than $100 nor more than $1,000 for each violation.

History:

1974 c 429 s 57

216B.58 PENALTIES; CONSTRUING ACT, OMISSION, AND FAILURE.

In construing and enforcing the provision of Laws 1974, chapter 429 relating to penalties, the act, omission, or failure of any officer, agent, or employee of any person acting within the scope of official duties of employment shall in every case be deemed to be also the act, omission, or failure of that person.

History:

1974 c 429 s 58; 1986 c 444

216B.59 CONTINUING VIOLATION.

Every violation of the provisions of Laws 1974, chapter 429 or of any lawful order of the commission, or any part or portion thereof by any person, is a separate and distinct offense, and in case of a continuing violation after a first conviction thereof each day's continuance thereof shall be deemed to be a separate and distinct offense.

History:

1974 c 429 s 59

216B.60 PENALTIES CUMULATIVE.

All penalties accruing under Laws 1974, chapter 429 shall be cumulative, and a suit for the recovery of one penalty shall not be a bar to or affect the recovery of any other penalty or forfeiture or be a bar to any criminal prosecution against any public utility or any officer, director, agent, or employee thereof or any person.

History:

1974 c 429 s 60

216B.61 ACTIONS TO RECOVER PENALTIES.

Actions to recover penalties under this chapter shall be brought in the name of the state of Minnesota in the district court of Ramsey County.


ASSESSMENTS

216B.62 REGULATORY EXPENSES.

Subdivision 1.

[Repealed, 1980 c 614 s 191]

Subd. 2.Assessing specific utility.

Whenever the commission or department, in a proceeding upon its own motion, on complaint, or upon an application to it, shall deem it necessary, in order to carry out the duties imposed under this chapter (1) to investigate the books, accounts, practices, and activities of, or make appraisals of the property of, any public utility, (2) to render any engineering or accounting services to any public utility, or (3) to intervene before an energy regulatory agency, the public utility shall pay the expenses reasonably attributable to the investigation, appraisal, service, or intervention. The commission and department shall ascertain the expenses, and the department shall render a bill therefor to the public utility, either at the conclusion of the investigation, appraisal, or services, or from time to time during its progress, which bill shall constitute notice of the assessment and a demand for payment. The amount of the bills so rendered by the department shall be paid by the public utility into the state treasury within 30 days from the date of rendition. The total amount, in any one calendar year, for which any public utility shall become liable, by reason of costs incurred by the commission within that calendar year, shall not exceed two-fifths of one percent of the gross operating revenue from retail sales of gas, or electric service by the public utility within the state in the last preceding calendar year. Where, pursuant to this subdivision, costs are incurred within any calendar year which are in excess of two-fifths of one percent of the gross operating revenues, the excess costs shall not be chargeable as part of the remainder under subdivision 3, but shall be paid out of the general appropriation to the department and commission. In the case of public utilities offering more than one public utility service only the gross operating revenues from the public utility service in connection with which the investigation is being conducted shall be considered when determining this limitation.

Subd. 3.Assessing all public utilities.

The department and commission shall quarterly, at least 30 days before the start of each quarter, estimate the total of their expenditures in the performance of their duties relating to public utilities under sections 216B.01 to 216B.67, other than amounts chargeable to public utilities under subdivision 2, 6, 7, or 8. The remainder shall be assessed by the commission and department to the several public utilities in proportion to their respective gross operating revenues from retail sales of gas or electric service within the state during the last calendar year. The assessment shall be paid into the state treasury within 30 days after the bill has been transmitted via mail, personal delivery, or electronic service to the several public utilities, which shall constitute notice of the assessment and demand of payment thereof. The total amount which may be assessed to the public utilities, under authority of this subdivision, shall not exceed one-sixth of one percent of the total gross operating revenues of the public utilities during the calendar year from retail sales of gas or electric service within the state. The assessment for the third quarter of each fiscal year shall be adjusted to compensate for the amount by which actual expenditures by the commission and department for the preceding fiscal year were more or less than the estimated expenditures previously assessed.

Subd. 3a.Supplemental staffing assessment.

In addition to other assessments in subdivision 3, the commission may assess up to $800,000 per year for supplemental staffing to implement requirements of this chapter. The amount in this subdivision shall be assessed to the several public utilities in proportion to their respective gross operating revenues from retail sales of gas or electric service within the state during the last calendar year and shall be deposited into an account in the special revenue fund. An assessment made under this subdivision is not subject to the cap on assessments provided in subdivision 3 or any other law.

Subd. 3b.Assessment for department regional and national duties.

In addition to other assessments in subdivision 3, the department may assess up to $1,000,000 per fiscal year for performing its duties under section 216A.07, subdivision 3a. The amount in this subdivision shall be assessed to energy utilities in proportion to their respective gross operating revenues from retail sales of gas or electric service within the state during the last calendar year and shall be deposited into an account in the special revenue fund and is appropriated to the commissioner of commerce for the purposes of section 216A.07, subdivision 3a. An assessment made under this subdivision is not subject to the cap on assessments provided in subdivision 3 or any other law. For the purpose of this subdivision, an "energy utility" means public utilities, generation and transmission cooperative electric associations, and municipal power agencies providing natural gas or electric service in the state. This subdivision expires June 30, 2015.

Subd. 4.Objections.

Within 30 days after the date of the transmittal of any bill as provided by subdivisions 2, 3, 7, and 8, the public utility against which the bill has been rendered may file with the commission objections setting out the grounds upon which it is claimed the bill is excessive, erroneous, unlawful, or invalid. The commission shall within 60 days hold a hearing and issue an order in accordance with its findings. The order shall be appealable in the same manner as other final orders of the commission.

Subd. 5.Assessing cooperatives and municipals.

The commission and department may charge cooperative electric associations, generation and transmission cooperative electric associations, municipal power agencies, and municipal electric utilities their proportionate share of the expenses incurred in the review and disposition of resource plans, adjudication of service area disputes, proceedings under section 216B.1691, 216B.2425, or 216B.243, and the costs incurred in the adjudication of complaints over service standards, practices, and rates. Cooperative electric associations electing to become subject to rate regulation by the commission pursuant to section 216B.026, subdivision 4, are also subject to this section. Neither a cooperative electric association nor a municipal electric utility is liable for costs and expenses in a calendar year in excess of the limitation on costs that may be assessed against public utilities under subdivision 2. A cooperative electric association, generation and transmission cooperative electric association, municipal power agency, or municipal electric utility may object to and appeal bills of the commission and department as provided in subdivision 4.

Subd. 5a.Assessing transmission companies.

The commission and department may charge transmission companies their proportionate share of the expenses incurred in the review and disposition of proceedings under sections 216B.2425, 216B.243, 216B.48, 216B.50, and 216B.79. A transmission company is not liable for costs and expenses in a calendar year in excess of the limitation on costs that may be assessed against public utilities under subdivision 2. A transmission company may object to and appeal bills of the commission and department as provided in subdivision 4.

Subd. 6.Administrative hearing costs.

Any amounts billed to the commission or the department by the Office of Administrative Hearings for public utility contested case hearings shall be assessed by the commission or the department against the public utility. The assessment shall be paid into the state treasury within 30 days after a bill, which constitutes notice of the assessment and demand for payment of it, has been transmitted to the public utility. Money received shall be credited to a special account and is appropriated to the commission or the department for payment to the Office of Administrative Hearings.

Subd. 7.Assessing all utilities.

The department shall assess public utilities, cooperative electric associations, and municipal utilities for the costs of activities under chapter 216C. The department shall not assess for costs of grants, loans, or other aids or for costs that can be recovered through other assessment authority. Each public utility, cooperative, and municipal utility shall be assessed in the proportion that its gross operating revenue for the sale of gas and electric service within the state for the last calendar year bears to the total of those revenues for all public utilities, cooperatives, and municipalities.

Subd. 8.Audit investigation costs; account, appropriation.

The audit investigation account is created as a separate account in the special revenue fund in the state treasury. If the commission, in a proceeding upon its own motion, on complaint, or upon an application to it, determines that it is necessary, in order to carry out its duties imposed under this chapter or chapter 216, 216A, 216E, 216F, or 216G, to conduct an investigation or audit of any public utility operations, practices, or policies requiring specialized technical professional investigative services for the inquiry, the commission may request the commissioner of commerce to seek authority from the commissioner of management and budget to incur costs reasonably attributable to the specialized services. If the investigation or audit is approved by the commissioner of management and budget, the commissioner of commerce shall carry out the investigation in the manner directed by the commission and shall render separate bills to the public utility for the costs incurred for such technical professional investigative services. The bill constitutes notice of the assessment and demand for payment. The amount assessed must be paid by the public utility to the commissioner of commerce within 30 days after the date of assessment. Money received under this subdivision must be deposited in the state treasury and credited to the audit investigation account, and is appropriated to the commissioner of commerce for the purposes of this subdivision.

216B.63 INTEREST ON ASSESSMENT.

The amounts assessed against any public utility not paid after 30 days after the transmittal of a notice advising the public utility of the amount assessed against it, draw interest at the rate of six percent per annum; and, upon failure to pay the assessment, the attorney general shall proceed by action in the name of the state against the public utility to collect the amount due, together with interest and the cost of the suit.


MISCELLANEOUS

216B.64 ATTORNEY GENERAL'S RESPONSIBILITIES.

The attorney general of the state shall, upon request of the commission or department, represent and appear for the commission or department in all actions and proceedings involving any question under Laws 1974, chapter 429, and shall aid in any investigation or hearing had under the provisions of Laws 1974, chapter 429. The attorney general shall perform all duties and services in connection with Laws 1974, chapter 429 and the enforcement thereof as the commission or department may require. The attorney general shall also bring all actions to collect penalties herein provided.

History:

1974 c 429 s 64; 1980 c 614 s 117; 1986 c 444

216B.65 DEPARTMENT TO EMPLOY NECESSARY STAFF.

The department may employ experts, engineers, statisticians, accountants, inspectors, clerks, hearing examiners who may be attorneys and employees it deems necessary to carry out the provisions of Laws 1974, chapter 429.

History:

1974 c 429 s 67

216B.66 CONSTRUCTION.

Laws 1974, chapter 429 is complete in itself and other Minnesota statutes are not to be construed as applicable to the supervision or regulation of public utilities by the commission. All acts and parts of acts in conflict with Laws 1974, chapter 429 are repealed insofar as they pertain to the regulation of public utilities as defined herein.

History:

1974 c 429 s 69

216B.67 CITATION.

Laws 1974, chapter 429, may be cited as the Minnesota Public Utilities Act.

History:

1974 c 429 s 71


MERCURY EMISSIONS REDUCTION

216B.68 DEFINITIONS; MERCURY EMISSIONS REDUCTION.

Subdivision 1.Scope.

Terms used in sections 216B.68 to 216B.688 have the meanings given them in this section and section 216B.02.

Subd. 2.Agency.

"Agency" means the Minnesota Pollution Control Agency.

Subd. 3.Dry scrubbed unit.

"Dry scrubbed unit" means a targeted unit at which pollution control technology that uses a spray dryer and fabric filter system to remove pollutants from air emissions is installed or will be installed by December 31, 2007.

Subd. 4.Federal mercury regulations.

"Federal mercury regulations" means the federal Clean Air Mercury Rule as of January 1, 2006, published in Code of Federal Regulations, title 40, parts 60, 63, 70, and 72.

Subd. 5.Mercury emissions reduction.

"Mercury emissions reduction" means the amount of mercury reduced from the emissions of a targeted or supplemental unit, relative to the emissions baseline from that unit established under section 216B.681, expressed as a percentage.

Subd. 6.Qualifying facility.

"Qualifying facility" means an electric generating power plant in Minnesota that, as of January 1, 2006, had a total net dependable capacity in excess of 500 megawatts from all coal-fired electric generating units at the power plant.

Subd. 7.Start-up period.

"Start-up period" means a period of one year after the date mercury-control equipment is installed at a targeted unit under an approved mercury emissions-reduction plan, or such longer period as the commission may approve after consultation with the Pollution Control Agency, if a longer period is necessary to optimize equipment performance for mercury reduction.

Subd. 8.Targeted unit.

"Targeted unit" means a coal-fired electric generation unit greater than 100 megawatts at a qualifying facility.

Subd. 9.Wet scrubbed unit.

"Wet scrubbed unit" means a targeted unit at which pollution control technology that uses water or solutions to remove pollutants from air emissions is installed.

History:

2006 c 201 s 5

216B.681 MONITORING MERCURY EMISSIONS.

By July 1, 2007, a public utility that owns or operates a qualifying facility shall install, maintain, and operate continuous mercury emission-monitoring systems or other method of monitoring approved by the agency on each targeted unit and, where applicable, on each supplemental unit pursuant to section 216B.6851. The monitoring systems must use methods set forth in federal mercury regulations or such other methods as may be approved by the agency. The public utility shall report to the agency as public data the quality assured data produced from monitoring implemented pursuant to this section on a quarterly basis in a form prescribed by the agency. The data from at least six months' monitoring must be used to establish a baseline for mercury emissions reductions under sections 216B.68 to 216B.688.

History:

2006 c 201 s 6

216B.682 MERCURY EMISSIONS-REDUCTION PLANS.

Subdivision 1.Dry scrubbed units.

(a) By December 31, 2007, a public utility that owns a dry scrubbed unit at a qualifying facility shall develop and submit to the agency and the commission a plan for mercury emissions reduction at each such unit. At each dry scrubbed unit owned and operated by the utility, the plan must propose to employ the available technology for mercury removal that is most likely to result in the removal of at least 90 percent of the mercury emitted from the unit.

(b) A plan submitted under this subdivision must provide for mercury emissions reduction at each dry scrubbed unit to be implemented by December 31, 2010. A public utility that owns two dry scrubbed targeted units must submit a plan that provides for implementation at one unit by December 31, 2009, and at the other unit by December 31, 2010.

Subd. 2.Wet scrubbed units.

(a) By December 31, 2009, a public utility that owns a wet scrubbed unit at a qualifying facility shall develop and submit to the agency and the commission a plan for mercury emissions reduction at each such unit. At each wet scrubbed unit owned by the utility, the plan must propose to employ the available technology for mercury removal that is most likely to result in the removal of at least 90 percent of the mercury emitted from the unit.

(b) A plan submitted under this subdivision must provide for mercury emissions reduction at each wet scrubbed unit to be implemented by December 31, 2014.

Subd. 3.Mercury emissions plans generally.

(a) In each plan submitted under this section, a utility shall present information assessing that plan's ability to optimize human health benefits and achieve cost efficiencies. Each plan must provide the cost, technical feasibility, and mercury emissions reduction expected for the utility's preferred technology option and each alternative considered. The utility shall demonstrate that it has considered achieving the mercury emissions reduction required under this section through multiple pollutant control technology.

(b) A plan submitted under this section may also:

(1) provide measures to reduce the cost and maximize the flexibility of each option proposed or considered; and

(2) specify permit targets or conditions proposed by the public utility for each mercury emission-control option proposed or considered, including, but not limited to, numeric emission targets, percent removal expectations, emission control technology installation and operation requirements or work practice standards, and potential changes in the performance of the mercury emissions-reduction technology over time.

(c) The utility may submit an emissions rate rider to the commission under section 216B.683 to recover the costs associated with plans filed under this section.

History:

2006 c 201 s 7

216B.683 MERCURY EMISSIONS REDUCTION; COST RECOVERY, FINANCIAL INCENTIVES.

Subdivision 1.Emissions-reduction riders.

(a) A public utility required to file a mercury emissions-reduction plan under sections 216B.68 to 216B.688 may also file for approval of emissions-reduction rate riders pursuant to section 216B.1692, subdivision 3, for its mercury control and other environmental improvement initiatives under sections 216B.68 to 216B.688.

(b) In addition to the cost recovery provided by section 216B.1692, subdivision 3, the emissions-reduction rate riders may include recovery of costs associated with (1) the purchase and installation of continuous mercury emission-monitoring systems, (2) costs associated with the purchase and installation of emissions-reduction equipment, (3) construction work in progress, (4) ongoing operation and maintenance costs associated with the utility's emission-control initiatives, including, but not limited to, the cost of any sorbent or emission-control reagent injected into the unit, (5) any project costs incurred before plan approval that are demonstrated to the commission's satisfaction to be part of the plan, and (6) any studies undertaken by the utility in support of the emissions-reduction plan.

(c) The utility may propose to phase in the emissions-reduction riders to recover these costs over the development and life of the projects.

Subd. 2.Performance-based incentives.

A mercury emissions-reduction rider approved by the commission may include performance-based financial incentives if the commission determines that the incentives will increase the likelihood that the utility will exceed 90 percent mercury emissions reductions, provided the incentives do not impose excessive costs on the utility's consumers when added to the costs recovered under subdivision 1. These incentives may include increased returns on investments or other performance-based incentives. The commission may structure the financial incentives to escalate for each additional increment of mercury emissions reduction achieved by the utility above the 90 percent mercury emissions reduction.

Subd. 3.Application of other law; associated rider.

(a) Section 216B.1692 applies to plans and emissions-control riders proposed under sections 216B.68 to 216B.688, except that:

(1) projects included in a plan approved under sections 216B.68 to 216B.688 are deemed to be qualifying projects for the purposes of section 216B.1692; and

(2) section 216B.1692, subdivisions 5, paragraph (c), and 6, do not apply to plans or riders submitted under sections 216B.68 to 216B.688.

(b) Commission approval of an emissions-reduction plan under this section includes approval of an emissions-reduction rider associated with that plan if submitted by the utility.

History:

2006 c 201 s 8

216B.684 ENVIRONMENTAL ASSESSMENT OF MERCURY EMISSIONS-REDUCTION PLAN.

The Pollution Control Agency shall evaluate a utility's mercury emissions-reduction plans filed under sections 216B.682 and 216B.6851 and submit its evaluation to the Public Utilities Commission within 180 days of the date the plan is filed with the agency and commission. In its review, the agency shall (1) assess whether the utility's plan meets the requirements of section 216B.682 or 216B.6851, as applicable, (2) evaluate the environmental and public health benefits of each option proposed or considered by the utility, including benefits associated with reductions in pollutants other than mercury, (3) assess the technical feasibility and cost-effectiveness of technologies proposed or considered by the utility for achieving mercury emissions reduction, and (4) advise the commission of the appropriateness of the utility's plan. In preparing its assessment, the agency may request additional information from the utility, especially with regard to alternative technologies or configurations applicable to the specific unit, and the estimated costs of those alternatives.

History:

2006 c 201 s 9

216B.685 MERCURY EMISSIONS-REDUCTION PLAN APPROVAL.

Subdivision 1.Commission review and evaluation.

The Public Utilities Commission shall review and evaluate a utility's mercury emissions-reduction plans and associated emissions-reduction riders submitted under section 216B.682 or pursuant to subdivision 2, paragraph (b). In its review, the commission shall consider the environmental and public health benefits, the agency's assessment of technical feasibility, competitiveness of customer rates, and cost-effectiveness of the utility's proposed mercury-control initiatives in light of the Pollution Control Agency's report under section 216B.684.

Subd. 2.Commission approval.

(a) Within 180 days of receiving the agency's report on a utility's plan filed under section 216B.682, subdivision 1 or 2, the commission shall order the implementation of a utility's mercury emissions-reduction plan and associated emissions-reduction rider that complies with the requirements of the applicable subdivision of section 216B.682, unless the commission determines that the plan as proposed fails to provide for increased environmental and health benefits or would impose excessive costs on the utility's customers.

(b) If the commission is unable to approve the utility's plan and associated emissions-reduction riders as proposed, it shall direct the utility to amend and resubmit its proposed plan in light of the record developed on the proposed plan or, at the utility's option, to file a new plan consistent with the requirements of the applicable subdivision of section 216B.682.

Subd. 3.Technical issues.

The commission shall give due consideration to the assessment of the Pollution Control Agency on compliance issues under sections 216B.68 to 216B.688, technical feasibility of emission-control technology, and environmental and public health benefits associated with emissions reductions.

Subd. 4.Equipment replacement; deadline extensions.

(a) Unless the utility proposes to do so, the commission may not require the replacement of existing pollution control equipment at a targeted or supplemental unit as a condition for approving a plan pursuant to this section or section 216B.6851.

(b) The commission may allow a utility up to two extensions of any deadline established under sections 216B.68 to 216B.688 or commission order under those sections, if the utility demonstrates the unavailability of necessary equipment or other extraordinary circumstances. An extension under this paragraph may last no longer than 12 months. The commission may not extend a deadline for final installation of pollution control equipment for longer than 12 months.

Subd. 5.Equipment optimization required.

A commission order under this section must require the utility to optimize the operation of equipment installed under a plan approved under this section to obtain maximum mercury reductions and to report the utility's efforts and results annually to the Pollution Control Agency, until such time as the agency determines the reports to be no longer necessary.

History:

2006 c 201 s 10

216B.6851 UTILITY OPTION.

Subdivision 1.Election.

A public utility with less than 200,000 customers subject to sections 216B.68 to 216B.688 that owns two wet scrubbed units at a qualifying facility may opt to be regulated under this section for those units in lieu of section 216B.682. Plans under this section are subject to section 216B.682, subdivision 3. Except where otherwise provided, all other provisions of sections 216B.68 to 216B.688 apply.

Subd. 2.Supplemental unit.

"Supplemental unit" means a coal-fired electric generation unit at an electric generating power plant in Minnesota at which mercury emissions-reduction measures are taken as part of an emissions-reduction plan under this section.

Subd. 3.Plan for 90 percent reduction required.

A public utility that elects to be regulated under this section must file a mercury emissions-reduction plan that is designed to achieve total mercury reduction at targeted and supplemental units owned by the utility equivalent to a goal of 90 percent reduction of mercury emissions at the utility's targeted units by December 31, 2018.

Subd. 4.Alternative plans.

The utility shall also submit one or more alternatives to the 90 percent reduction plan required under subdivision 3. Alternative plans must be designed to come as near as technically possible to achieving the goal established in subdivision 3 without imposing excessive costs on the utility's customers.

Subd. 5.Early action; wet scrubbed units.

(a) The utility electing for regulation under this section shall file an initial plan for mercury emissions reduction at one of its two wet scrubbed units on or before December 31, 2007. The plan must provide for mercury emissions reduction to be implemented at that unit by December 31, 2010. If the plan is approved by the commission, and implemented by the utility, the utility may have until July 1, 2015, to file its plans for reduction at its other wet scrubbed unit at the qualifying facility, and may have until December 31, 2018, to implement mercury emissions reduction at that unit.

(b) Until the utility files its plans for the other wet scrubbed unit, the utility must submit to the commission and agency, by July 1 each year, beginning in 2011, a report containing the following information:

(1) mercury control plans for units subject to this section, including how elements of the plans may affect the performance and cost-effectiveness of emission controls for air pollutants other than mercury;

(2) an assessment of the impacts of federal laws regulating various air pollutants emitted by coal-fired power plants that can reasonably be expected to be enacted by 2018 on the utility's units subject to this section, and potential utility responses to those laws, including, but not limited to:

(i) installing pollution control equipment;

(ii) using pollution allowances to achieve regulatory compliance; and

(iii) retiring or repowering the plant that is the subject of the filing with cleaner fuels considering the costs of complying with state and federal environmental regulations.

For each potential response, the report must include an analysis of the impacts on ratepayers, the utility's financial position, and utility operations, including the impacts on the service life of affected units.

(c) The utility shall consult with the agency, the Department of Commerce, and other interested stakeholders to determine which future federal laws to assess under paragraph (b), clause (2), and the scope of the assessment of the impact of those laws.

Subd. 6.Agency review and commission approval.

(a) The agency shall review the utility's plans as provided in section 216B.684.

(b) The Public Utilities Commission shall review and evaluate a utility's mercury emissions-reduction plans submitted under this section. In its review, the commission shall consider the environmental and public health benefits, the agency's determination of technical feasibility, competitiveness of customer rates, and cost-effectiveness of the utility's proposed mercury-control initiatives in light of the Pollution Control Agency's review under paragraph (a). Within 180 days of receiving the agency's report, the commission shall approve a utility's mercury emissions-reduction plan that the commission reasonably expects will come closest to achieving total mercury reductions at targeted and supplemental units owned by the utility equivalent to a goal of 90 percent reduction of mercury emissions at the utility's targeted units by December 31, 2018, in a manner that provides for increased environmental and public health benefits without imposing excessive costs on the utility's customers. If the commission is unable to approve the utility's 90 percent reduction plan filed under subdivision 3, the commission, in consultation with the Pollution Control Agency, shall order the utility to implement the most stringent mercury-control alternative proposed by the utility under this section that provides for increased environmental and public health benefits without imposing excessive costs on the utility's customers.

(c) At each targeted and supplemental unit included in a plan under this section, a utility shall propose to implement mercury emissions-control measures that will result in the greatest reduction of mercury emitted from that unit that is technically feasible without imposing excessive costs.

216B.686 OTHER ENVIRONMENTAL IMPROVEMENT PLANS.

Subdivision 1.Utility filing.

(a) In order to encourage a utility to address multiple pollutants, a utility required to submit mercury-reduction plans under sections 216B.68 to 216B.688 may also propose plans for investments and related expenses in pollution control equipment to be installed at facilities in Minnesota needed to comply with state or federal emission-control statutes or regulations that became effective after December 31, 2004.

(b) For each plan, the utility must show that the investments in pollution control equipment to be installed at facilities in Minnesota under the plan will provide for increased environmental and public health benefits, do not impose excessive costs on the utility's customers, and will achieve at least the pollution control required by applicable state or federal regulations.

Subd. 2.Emissions-reduction riders.

A public utility that files a plan under this section may also file for approval of an emissions-reduction rate rider under section 216B.683, subdivision 1.

Subd. 3.Agency review.

(a) The Pollution Control Agency shall evaluate a utility's plans filed under this section and, within 180 days of receiving the filing, provide the commission with:

(1) verification that the emissions-reduction project qualifies under subdivision 1;

(2) a description of the projected environmental benefits of the proposed project; and

(3) its assessment of the appropriateness of the proposed plans.

(b) In preparing its review under this subdivision, the agency may request additional information from the utility, especially with regard to alternative technologies or configurations applicable to a specific unit, and the estimated costs of those alternatives.

Subd. 4.Commission approval.

The commission shall review and evaluate a utility's plans and associated emissions-reduction riders for other environmental improvement initiatives submitted under this section. The commission shall consider the overall environmental and public health benefits, total costs, and competitiveness of customer rates. Within 180 days of receiving the agency's report prepared under subdivision 3, the commission shall approve the plan and associated emissions-reduction rider if the commission finds that it meets the requirements of subdivision 1, paragraph (b).

History:

2006 c 201 s 12

216B.687 MERCURY EMISSIONS REDUCTION IMPLEMENTATION, OPERATION.

Subdivision 1.Permit conditions for mercury reductions.

The agency shall establish the mercury emissions reduction for each targeted unit included in a plan approved under section 216B.685, or where applicable, for each targeted and supplemental unit included in a plan approved under section 216B.6851.

Subd. 2.Enforcement by agency.

(a) Except as required by federal regulation, any mercury reduction incorporated into the permit for a targeted unit as established under a plan approved under section 216B.685, or where applicable, for each targeted and supplemental unit included in a plan approved under section 216B.6851, must be a state-only condition of the permit and will not be enforced by the agency during the start-up period.

(b) After the start-up period ends, the Pollution Control Agency shall incorporate into the permit the mercury reduction reasonably expected to be achieved at each unit or facility as an enforceable state-only reduction. For a qualifying facility with multiple units that has one or more units included in approved plans, the agency may establish the mercury emissions reduction for the facility covering all targeted and supplemental units at that facility after the start-up periods for all units have concluded, and the actual mercury emissions for the units have been determined. In setting the reduction, the agency shall give due consideration to the results of monitoring before implementation of the plan, the results of monitoring during the start-up period, and any factors that may impact the performance of the unit for the next five years.

Subd. 3.Equipment optimization required.

The agency shall revise the unit's air permit every five years to ensure optimal mercury emissions reduction by equipment installed under an approved plan, in light of technical and operational advances made since the date of plan approval. In revising the unit's air permit, the agency may recommend, but shall not require, additional investments in pollution control equipment, or the removal of equipment installed pursuant to an approved plan. The utility may seek commission review of the costs associated with a permit requirement or request for equipment optimization proposed by the agency and, if review is requested, the revision is not effective until approved by the commission. The commission shall approve the revision unless the utility or other party shows that it will impose excessive consumer costs.

History:

2006 c 201 s 13

216B.688 RELATIONSHIP TO OTHER STATE FINANCIAL REQUIREMENTS.

Except as otherwise provided for equipment optimization as specified in section 216B.687, a public utility implementing an approved mercury emissions-reduction plan is not required to undertake additional investments or incur additional operating or maintenance costs to reduce mercury at a unit included in a plan approved under section 216B.685 or 216B.6851.

History:

2006 c 201 s 14


PREVENTATIVE MAINTENANCE

216B.79 PREVENTATIVE MAINTENANCE.

The commission may order public utilities to make adequate infrastructure investments and undertake sufficient preventative maintenance with regard to generation, transmission, and distribution facilities. The commission's authority under this section also applies to any transmission company that owns or operates electric transmission lines in Minnesota.

216B.81 [Renumbered 216B.029]

HYDROGEN ENERGY

216B.8109 HYDROGEN ENERGY ECONOMY GOAL.

It is a goal of this state that Minnesota move to hydrogen as an increasing source of energy for its electrical power, heating, and transportation needs.

216B.811 DEFINITIONS.

Subdivision 1.Scope.

For purposes of sections 216B.811 to 216B.815, the terms defined in this section have the meanings given them.

Subd. 2.Fuel cell.

"Fuel cell" means an electrochemical device that produces useful electricity, heat, and water vapor, and operates as long as it is provided fuel.

Subd. 3.Hydrogen.

"Hydrogen" means hydrogen produced using renewable energy sources.

Subd. 4.Related technologies.

"Related technologies" means balance of plant components necessary to make hydrogen and fuel cell systems function; turbines, reciprocating, and other combustion engines capable of operating on hydrogen; and electrolyzers, reformers, and other equipment and processes necessary to produce, purify, store, distribute, and use hydrogen for energy.

216B.812 FOSTERING USE OF HYDROGEN ENERGY.

Subdivision 1.State purchase and use of renewable hydrogen technologies.

(a) The Department of Commerce, in coordination with the Department of Administration and the Pollution Control Agency, shall identify opportunities for deploying renewable hydrogen, fuel cells, and related technologies within state-owned facilities, vehicle fleets, and operations in ways that demonstrate their commercial performance and economics.

(b) The Department of Commerce shall recommend to the Department of Administration the purchase and deployment of hydrogen, fuel cells, and related technologies, when feasible, in ways that strategically contribute to realizing Minnesota's hydrogen economy goal as set forth in section 216B.8109, and which contribute to the following nonexclusive list of objectives:

(1) provide needed performance data to the marketplace;

(2) identify code and regulatory issues to be resolved;

(3) foster economic development and job creation in the state;

(4) raise public awareness of renewable hydrogen, fuel cells, and related technologies; or

(5) reduce emissions of carbon dioxide and other pollutants.

(c) The Department of Commerce and the Pollution Control Agency shall also recommend to the Department of Administration changes to the state's procurement guidelines and contracts in order to facilitate the purchase and deployment of cost-effective renewable hydrogen, fuel cells, and related technologies by all levels of government.

Subd. 2.Pilot projects.

(a) In consultation with appropriate representatives from state agencies, local governments, universities, businesses, and other interested parties, the Department of Commerce shall report back to the legislature by November 1, 2005, and every two years thereafter, with a slate of proposed pilot projects that contribute to realizing Minnesota's hydrogen economy goal as set forth in section 216B.8109. The Department of Commerce must consider the following nonexclusive list of priorities in developing the proposed slate of pilot projects:

(1) deploy "bridge" technologies such as hybrid-electric, off-road, and fleet vehicles running on hydrogen or fuels blended with hydrogen;

(2) lead to cost-competitive, on-site renewable hydrogen production technologies;

(3) demonstrate nonvehicle applications for hydrogen;

(4) improve the cost and efficiency of hydrogen from renewable energy sources; and

(5) improve the cost and efficiency of hydrogen production using direct solar energy without electricity generation as an intermediate step.

(b) For deployment projects that do not involve a demonstration component, individual system components of the technology should, if feasible, meet commercial performance standards and systems modeling must be completed to predict commercial performance, risk, and synergies. In addition, the proposed pilots should meet as many of the following criteria as possible:

(1) advance energy security;

(2) capitalize on the state's native resources;

(3) result in economically competitive infrastructure being put in place;

(4) be located where it will link well with existing and related projects and be accessible to the public, now or in the future;

(5) demonstrate multiple, integrated aspects of renewable hydrogen infrastructure;

(6) include an explicit public education and awareness component;

(7) be scalable to respond to changing circumstances and market demands;

(8) draw on firms and expertise within the state where possible;

(9) include an assessment of its economic, environmental, and social impact; and

(10) serve other needs beyond hydrogen development.

Subd. 3.Establishing multifuel hydrogen fueling stations.

The commissioner of commerce may accept federal funds, expend funds, and participate in projects to design, site, and construct multifuel hydrogen fueling stations that eventually link urban centers along key trade corridors across the jurisdictions of Manitoba, the Dakotas, Minnesota, Iowa, and Wisconsin.

These energy stations must serve the priorities listed in subdivision 2 and, as transition infrastructure, should accommodate a wide variety of vehicle technologies and fueling platforms, including hybrid, flexible-fuel, and fuel cell vehicles. They may offer, but not be limited to, gasoline, diesel, ethanol (E-85), biodiesel, and hydrogen, and may simultaneously test the integration of on-site combined heat and power technologies with the existing energy infrastructure.

The hydrogen portion of the stations may initially serve local, dedicated on- or off-road vehicles, but should eventually support long-haul transport.

216B.813 MINNESOTA RENEWABLE HYDROGEN INITIATIVE.

Subdivision 1.Road map.

The Department of Commerce shall coordinate and administer directly or by contract the Minnesota renewable hydrogen initiative. If the department decides to contract for its duties under this section, it must contract with a nonpartisan, nonprofit organization within the state to develop the road map. The initiative may be run as a public-private partnership representing business, academic, governmental, and nongovernmental organizations. The initiative must oversee the development and implementation of a renewable hydrogen road map, including appropriate technology deployments, that achieve the hydrogen goal of section 216B.8109. The road map should be compatible with the United States Department of Energy's National Hydrogen Energy Roadmap and be based on an assessment of marketplace economics and the state's opportunities in hydrogen, fuel cells, and related technologies, so as to capitalize on strengths. The road map should establish a vision, goals, general timeline, strategies for working with industry, and measurable milestones for achieving the state's renewable hydrogen goal. The road map should describe how renewable hydrogen and fuel cells fit in Minnesota's overall energy system, and should help foster a consistent, predictable, and prudent investment environment. The department must report to the legislature on the progress in implementing the road map by November 1 of each odd-numbered year.

Subd. 2.Grants.

(a) The commissioner of commerce shall operate a competitive grant program for projects to assist the state in attaining its renewable hydrogen energy goals. The commissioner of commerce shall assemble an advisory committee made up of industry, university, government, and nongovernment organizations to:

(1) help identify the most promising technology deployment projects for public investment;

(2) advise on the technical specifications for those projects; and

(3) make recommendations on project grants.

(b) The commissioner shall give preference to project concepts included in the department's most recent biennial report: Strategic Demonstration Projects to Accelerate the Commercialization of Renewable Hydrogen and Related Technologies in Minnesota. Projects eligible for funding must combine one or more of the hydrogen production options listed in the department's report with an end use that has significant commercial potential, preferably high visibility, and relies on fuel cells or related technologies. Each funded technology deployment must include an explicit education and awareness-raising component, be compatible with the renewable hydrogen deployment criteria defined in section 216B.812, and receive 50 percent of its total cost from nonstate sources. The 50 percent requirement does not apply for recipients that are public institutions.

216B.815 REGIONAL ENERGY RESEARCH AND EDUCATION PARTNERSHIP.

(a) The state's public research and higher education institutions should work with one another and with similar institutions in the region to establish Minnesota and the Upper Midwest as a center of research, education, outreach, and technology transfer for the production of renewable energy and products, including hydrogen, fuel cells, and related technologies. The partnership should be designed to create a critical mass of research and education capability that can compete effectively for federal and private investment in these areas.

(b) The partnership must include an advisory committee comprised of government, industry, academic, and nonprofit representatives to help focus its research and education efforts on the most critical issues.

(c) Initiatives undertaken by the partnership may include:

(1) collaborative and interdisciplinary research, demonstration projects, and commercialization of market-ready technologies;

(2) creation of undergraduate and graduate course offerings and eventually degreed and vocational programs with reciprocity;

(3) establishment of fellows programs at the region's institutes of higher learning that provide financial incentives for relevant study, research, and exchange; and

(4) development and field-testing of relevant curricula, teacher kits for all educational levels, and widespread teacher training, in collaboration with state energy offices, teachers, nonprofits, businesses, the United States Department of Energy, and other interested parties.


LOCAL POWER QUALITY ZONES

216B.82 LOCAL POWER QUALITY ZONES.

(a) Upon joint petition of a public utility as defined in section 216B.02, subdivision 4, and any customer located within the utility's service territory, the commission may establish a zone within that utility's service territory where the utility will install additional, redundant, or upgraded components of the electric distribution infrastructure that are designed to decrease the risk of power outages, provided the utility and all of its customers located within the proposed zone have approved the installation of the components and the financial recovery plan prior to the creation of the zone. Prior to commission approval, the utility must notify each customer within the proposed zone of the total costs of the installation, an estimate of the customer's share of those costs, and the potential benefits of the local power quality zone to the customer.

(b) The commission shall authorize the utility to collect all costs of the installation of any components under this section, including initial investment, operation, and maintenance costs, and taxes from all customers within the zone, through tariffs and surcharges for service in a zone that appropriately reflect the cost of service to those customers, provided the customers agree to pay all costs for a predetermined period, including costs of component removal, if appropriate.

(c) Nothing in this section limits the ability of the utility and any customer to enter into customer-specific agreements pursuant to applicable statutory, rule, or tariff provisions.

Nothing in this section shall be construed to permit the quality of service outside a designated zone to decline.

700 State Office Building, 100 Rev. Dr. Martin Luther King Jr. Blvd., St. Paul, MN 55155 ♦ Phone: (651) 296-2868 ♦ TTY: 1-800-627-3529 ♦ Fax: (651) 296-0569