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CHAPTER 216B. PUBLIC UTILITIES

Table of Sections
SectionHeadnote
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.
216B.091216B.091 MONTHLY REPORTS.
216B.095DISCONNECTION DURING COLD WEATHER.
216B.0951216B.0951 PROPANE PREPURCHASE PROGRAM.
216B.096216B.096 COLD WEATHER RULE; PUBLIC UTILITY.
216B.097COLD WEATHER RULE; COOPERATIVE OR MUNICIPAL UTILITY.
216B.0975DISCONNECTION DURING EXTREME HEAT CONDITIONS.
216B.098RESIDENTIAL CUSTOMER PROTECTIONS.
216B.10ACCOUNTING.
216B.105216B.105 CUSTOMER 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.162COMPETITIVE RATE FOR ELECTRIC UTILITY.
216B.1621ELECTRIC SERVICE AGREEMENT.
216B.163FLEXIBLE TARIFF.
216B.1635RECOVERY OF GAS UTILITY INFRASTRUCTURE COSTS.
216B.1636216B.1636 RECOVERY OF ELECTRIC UTILITY INFRASTRUCTURE COSTS.
216B.1637216B.1637 RECOVERY OF CERTAIN LIMITED UTILITY GREENHOUSE GAS INFRASTRUCTURE COSTS.
216B.164COGENERATION AND SMALL POWER PRODUCTION.
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.1681216B.1681 CURTAILMENT PAYMENTS.
216B.169RENEWABLE AND HIGH-EFFICIENCY ENERGY RATE OPTIONS.
216B.1691RENEWABLE ENERGY OBJECTIVES.
216B.1692EMISSIONS-REDUCTION RIDER.
216B.1693CLEAN ENERGY TECHNOLOGY.
216B.1694INNOVATIVE ENERGY PROJECT.

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.2401216B.2401 ENERGY CONSERVATION POLICY GOAL.
216B.241ENERGY CONSERVATION IMPROVEMENT.
216B.2411DISTRIBUTED ENERGY RESOURCES.
216B.2412216B.2412 DECOUPLING OF ENERGY SALES FROM REVENUES.
216B.242NATURAL GAS INVERTED RATES PROGRAM.
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.
216B.243CERTIFICATE OF NEED FOR LARGE ENERGY FACILITY.
216B.244NUCLEAR PLANT CAPACITY REQUIREMENTS.
216B.245PUMP AND STORE HYDROPOWER FACILITY; PROHIBITION.

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.68216B.68 DEFINITIONS; MERCURY EMISSIONS REDUCTION.
216B.681216B.681 MONITORING MERCURY EMISSIONS.
216B.682216B.682 MERCURY EMISSIONS-REDUCTION PLANS.
216B.683216B.683 MERCURY EMISSION REDUCTION; COST RECOVERY, FINANCIAL INCENTIVES.
216B.684216B.684 ENVIRONMENTAL ASSESSMENT OF MERCURY EMISSION-REDUCTION PLAN.
216B.685216B.685 MERCURY EMISSIONS-REDUCTION PLAN APPROVAL.
216B.6851216B.6851 UTILITY OPTION.
216B.686216B.686 OTHER ENVIRONMENTAL IMPROVEMENT PLANS.
216B.687216B.687 MERCURY EMISSIONS REDUCTION IMPLEMENTATION, OPERATION.
216B.688216B.688 RELATIONSHIP 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.813216B.813 MINNESOTA RENEWABLE HYDROGEN INITIATIVE.
216B.815REGIONAL ENERGY RESEARCH AND EDUCATION PARTNERSHIP; GOALS.
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.
History: 1974 c 429 s 1; 1978 c 795 s 1; 1989 c 356 s 8
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. 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 or
(2) a retail seller of compressed natural gas used as a vehicular fuel which purchases the gas from
a public utility. 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.
History: 1974 c 429 s 2; 1978 c 795 s 2; 1980 c 614 s 123; 1981 c 17 s 1; 1981 c 144 s 1;
1981 c 365 s 9; 1983 c 366 s 1,2; 1984 c 428 s 1; 1985 c 248 s 70; 1989 c 356 s 9; 1Sp2001 c 4
art 6 s 34-36; 2005 c 97 art 1 s 1
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) 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.
(b) For a cooperative electric association that is the product of a merger or consolidation
of three or more associations between December 30, 1996, and January 1, 2001, the number of
members or stockholders necessary to initiate the petition shall be no less than one percent of the
members or stockholders of the association.
    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.
History: 1981 c 144 s 2; 2000 c 292 s 1-3
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.
History: 1983 c 162 s 1; 1989 c 144 art 2 s 3; 1989 c 356 s 10
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 326.243.
    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

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.
History: 1974 c 429 s 3; 1983 c 179 s 4; 1987 c 312 art 1 s 10 subd 1
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.
History: 1987 c 9 s 1; 1990 c 370 s 1; 1992 c 478 s 1
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.
History: 1974 c 429 s 5; 1985 c 248 s 70; 1997 c 191 art 1 s 1
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.
History: 1974 c 429 s 6; 1978 c 795 s 3
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.
History: 1974 c 429 s 8; 1985 c 248 s 70
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.
History: 1974 c 429 s 9; 1985 c 248 s 70; 1993 c 327 s 3
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.
History: 2007 c 57 art 2 s 11
216B.095 DISCONNECTION DURING COLD WEATHER.
(a) The commission shall amend its rules governing disconnection of residential utility
customers who are unable to pay for utility service during cold weather to include the following:
(1) coverage of customers whose household income is less than 50 percent of the state
median income;
(2) a requirement that a customer who pays the utility at least ten percent of the customer's
income or the full amount of the utility bill, whichever is less, in a cold weather month cannot be
disconnected during that month. The customer's income means the actual monthly income of the
customer or the average monthly income of the customer computed on an annual calendar year,
whichever is less, and does not include any amount received for energy assistance;
(3) that the ten percent figure in clause (2) must be prorated between energy providers
proportionate to each provider's share of the customer's total energy costs where the customer
receives service from more than one provider;
(4) verification of income by the local energy assistance provider or the utility, unless the
customer is automatically eligible for protection against disconnection as a recipient of any form
of public assistance, including energy assistance, that uses income eligibility in an amount at
or below the income eligibility in clause (1);
(5) a requirement that the customer receive referrals to energy assistance, weatherization,
conservation, or other programs likely to reduce the customer's energy bills; and
(6) a requirement that customers who have demonstrated an inability to pay on forms
provided for that purpose by the utility, and who make reasonably timely payments to the
utility under a payment plan that considers the financial resources of the household, cannot be
disconnected from utility service from October 15 through April 15. A customer who is receiving
energy assistance is deemed to have demonstrated an inability to pay.
(b) 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.
History: 1989 c 338 s 1; 1989 c 356 s 59; 2001 c 212 art 4 s 1; 1Sp2003 c 11 art 3 s 1
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.
History: 2007 c 57 art 2 s 12
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 or by first class mail, 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.
    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 any 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
NOTE:This section as added by Laws 2007, chapter 57, article 2, section 13, is effective
September 1, 2008. Laws 2007, chapter 57, article 2, section 43.
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.
History: 1991 c 235 art 2 s 1; 2001 c 212 art 4 s 2; 1Sp2003 c 11 art 3 s 2; 2007 c 57 art
2 s 14,15
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.
History: 1Sp2003 c 11 art 3 s 3
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.
    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.
History: 2001 c 212 art 4 s 3; 2002 c 379 art 1 s 54; 2007 c 57 art 2 s 16
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.
History: 1974 c 429 s 11; 1981 c 142 s 2

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 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 another previously filed case involving changes in general rates under
this section or section 237.075, the commission may extend the suspension period to the extent
necessary to allow itself 20 working days to make the final determination after it has made a final
determination in the previously filed case. 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 (i), 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) Investments and expenses for energy conservation improvements shall not be included
by the commission in the determination of (i) just and reasonable electric and gas rates for retail
electric and gas service provided to large electric customer facilities that have been exempted by
the commissioner of the department pursuant to section 216B.241, subdivision 1a, paragraph (b);
or (ii) just and reasonable gas rates for large energy facilities.
    (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 and gas rates applicable to large
electric customer facilities that have been exempted by the commissioner of the department
pursuant to section 216B.241, subdivision 1a, paragraph (b), and to reduce the gas rate applicable
to a large energy facility 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) compensate the utility for earnings lost as a result of its conservation programs.
    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 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; or
(3) costs for fuel used in generation of electricity or the manufacture of gas.
    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 of 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.
(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;
(2) 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;
(3) 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;
(4) allows for recovery of other expenses if shown to promote a least-cost project option or
is otherwise in the public interest;
(5) allocates project costs appropriately between wholesale and retail customers;
(6) 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
(7) 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. 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 which the commission deems prudent and which qualify under
section 290.21, subdivision 3, clause (b). Only 50 percent of the qualified contributions shall
be 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 300 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 300
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. By September 1, 2007, 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.
History: 1974 c 429 s 16; 1977 c 359 s 1-6; 1977 c 364 s 5; 1978 c 694 s 1; 1980 c 579 s 16;
1980 c 614 s 123; 1980 c 615 s 60; 1981 c 357 s 70; 1Sp1981 c 4 art 4 s 15; 1982 c 414 s 1-6;
1982 c 424 s 130; 1983 c 179 s 5; 1983 c 247 s 95; 1983 c 289 s 104; 1986 c 346 s 1; 1986 c 409
s 6,7; 1987 c 353 s 6; 1988 c 457 s 1-3; 1991 c 147 s 1; 1991 c 184 s 1; 1991 c 235 art 1 s 1; art 6
s 1; 1993 c 49 s 1; 1993 c 327 s 4-7; 1994 c 483 s 1; 1994 c 641 art 4 s 2,3; 1994 c 644 s 2; 1995
c 17 s 2; 1995 c 125 s 1; 1995 c 224 s 74,75; 1997 c 25 s 1,3; 1997 c 231 art 2 s 5; 1999 c 140 s
1; 2001 c 212 art 4 s 4; 1Sp2001 c 4 art 6 s 37-40; 2004 c 138 s 4; 2004 c 216 s 2; 2005 c 97 art 1
s 2,3; art 12 s 1; 2007 c 57 art 2 s 18,19; 2007 c 136 art 2 s 1,2

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 469.134 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]
History: 1990 c 370 s 2,7; 1995 c 9 s 1,2; 1996 c 471 art 7 s 2
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.
History: 2001 c 212 art 3 s 1
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 owner" means:
    (1) a Minnesota resident;
    (2) a limited liability company that is organized under chapter 322B and that is made up of
members who are Minnesota residents;
    (3) a Minnesota nonprofit organization organized under chapter 317A;
    (4) 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;
    (5) 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, 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; or
    (6) a tribal council.
    (d) "Net present value rate" means a rate equal to the net present value of the nominal
payments to a project divided by the total expected energy production of the project over the life
of its power purchase agreement.
    (e) "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.
    (f) "Renewable" refers to a technology listed in section 216B.1691, subdivision 1, paragraph
(a).
    (g) "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 owner 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 owner is a public entity listed under paragraph (b), clause (5), that is not a municipal
utility;
    (2) demonstrates that at least 51 percent of the gross revenues from a power purchase
agreement over the life of the project will flow to qualifying owners and other local entities; 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.
    Subd. 3. Tariff rate. (a) The tariff described in subdivision 4 must have a rate schedule that
allows for a net present value rate over the 20-year life of the power purchase agreement. The
tariff must provide for a rate that is higher in the first ten years of the power purchase agreement
than in the last ten years. The discount rate required to calculate the net present value must be the
utility's normal discount rate used for its other business purposes.
    (b) The commission shall consider mechanisms to encourage the aggregation of C-BED
projects.
    (c) The commission shall require that qualifying and nonqualifying owners provide sufficient
security to secure performance under the power purchase agreement, and shall prohibit the
transfer of the C-BED project to a nonqualifying owner during the initial 20 years of the contract.
    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.1691that 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 owners, 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 qualifying owner, or any combination of qualifying owners, may develop a joint
venture project with a nonqualifying renewable energy project developer. 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 equity share of the project owned by the qualifying owners.
    (d) 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.
    (e) 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.
History: 2005 c 97 art 2 s 1; 2006 c 212 art 1 s 11; 2007 c 136 art 4 s 1-7
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
foregone due to the discretionary rate reductions, nor shall the commission grant such recovery.
History: 1990 c 370 s 3,7; 1993 c 190 s 1; 1995 c 6 s 1; 1997 c 191 art 1 s 2-5; 1Sp2001 c
4 art 6 s 41,42
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]
History: 1987 c 371 s 1,4; 1990 c 593 s 1,2
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 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; and
(3) replace or modify existing infrastructure if the replacement or modification does not
constitute a betterment, unless the betterment is required by a political subdivision, as evidenced
by specific documentation from the government entity requiring the replacement or modification
of infrastructure.
(c) "Gas utility projects" means relocation and 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.
    Subd. 2. Filing. (a) The commission may approve a gas utility's petition for a rate schedule
to recover GUIC under this section. A gas utility may petition the commission to recover a
rate of return, income taxes on the rate of return, incremental property taxes, plus incremental
depreciation expense associated with GUIC.
(b) The filing is subject to the following:
(1) A gas utility may submit a filing under this section no more than once per year.
(2) A gas utility must file sufficient information to satisfy the commission regarding the
proposed GUIC or be subject to denial by the commission. The information includes, but is
not limited to:
(i) the government entity ordering the gas utility project and the purpose for which the
project is undertaken;
(ii) the location, description, and costs associated with the project;
(iii) a description of the costs, and salvage value, if any, associated with the existing
infrastructure replaced or modified as a result of the project;
(iv) the proposed rate design and an explanation of why the proposed rate design is in the
public interest;
(v) the magnitude and timing of any known future gas utility projects that the utility may
seek to recover under this section;
(vi) 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;
(vii) the magnitude of GUIC in relation to the gas utility's capital expenditures since its
most recent general rate case;
(viii) 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; and
(ix) documentation supporting the calculation of the GUIC.
    Subd. 3. Commission authority; rules. The commission may issue orders and adopt rules
necessary to implement and administer this section.
History: 2005 c 97 art 10 s 1

NOTE: This section as added by Laws 2005, chapter 97, article 10, section 1, expires June
30, 2015. Laws 2005, chapter 97, article 10, section 3.
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.
History: 2007 c 136 art 2 s 3
216B.1637 RECOVERY OF CERTAIN LIMITED UTILITY GREENHOUSE GAS
INFRASTRUCTURE COSTS.
    A public utility that owns a nuclear power plant and a public utility furnishing gas service
may file for recovery of investments and expenses associated with the replacement of cast
iron natural gas distribution and service lines owned by the utility and to replace breakers that
contain sodium hexafluoride in order to reduce the risk of greenhouse gases being released into
the atmosphere. Upon a finding that the projects are consistent with the public interest and
do not impose excessive costs on customers, the commission shall provide timely recovery
of the utility's investment and expenses on any approved projects through a rate adjustment
mechanism similar to that provided for transmission projects under section 216B.16, subdivision
7b
, paragraphs (b) to (d).
History: 2007 c 57 art 2 s 20
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 apply to all Minnesota
electric utilities, including cooperative electric associations and municipal electric utilities.
    Subd. 3. Purchases; small facilities. (a) 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 (b) or (c).
(b) 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.
(c) 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.
(d) If the qualifying 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 having less than 40-kilowatt capacity
may, at the customer's option, elect to be governed by the provisions of subdivision 4.
    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 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. 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 qualifying facility having less than 40-kilowatt
capacity.
(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 qualifying facility having less than
40-kilowatt capacity, except that existing contracts may remain in force until written notice of
election that the uniform statewide contract form applies is given by either party to the other, with
the notice being of the shortest time period permitted under the existing contract for termination
of the existing contract by either party, but not less than ten nor longer than 30 days.
    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 subdivisions
5 and 7, 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.
History: 1981 c 237 s 1; 1983 c 301 s 166-171; 1984 c 640 s 32; 1991 c 315 s 1; 1993 c 356
s 1; 1996 c 305 art 2 s 38
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 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, 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; or
(2) 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,
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 owned 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.
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, provided that the utility demonstrates to the commission's satisfaction that the expenses
improve project economics, ensure project implementation, 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.
History: 1997 c 176 s 1; 1998 c 345 s 1; 1999 c 200 s 2; 2001 c 212 art 8 s 1; 1Sp2003 c 11
art 1 s 3; 2005 c 97 art 2 s 2; 2007 c 136 art 4 s 8
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.
History: 1Sp2001 c 5 art 3 s 11; 2002 c 377 art 4 s 3; 2002 c 398 s 2; 2002 c 400 s 12
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.
History: 1997 c 25 s 2,3; 1Sp2001 c 4 art 6 s 43; 2004 c 138 s 1-4
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.
History: 2007 c 136 art 4 s 9
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) Each utility shall offer
its customers, and shall advertise the offer at least annually, 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) Each public utility shall file an implementation plan within 90 days of July 1, 2001, to
implement paragraph (a).
(c) 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 renewable energy
and the cost of generating or purchasing the same amount of nonrenewable energy; and
(2) be distributed on a per kilowatt-hour basis among all customers who choose to participate
in the program.
(d) Implementation of these rate options may reflect a reasonable amount of lead time
necessary to arrange acquisition of the energy. 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. If a utility is not able to arrange an adequate supply of renewable
or high-efficiency energy to meet its customers' demand under this section, the utility must file a
report with the commission detailing its efforts and reasons for its failure.
    Subd. 3. Certification and tradeable 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 tradeable credits for eligible power supplies.
History: 2001 c 212 art 8 s 2
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 clause; or (5) biomass, which includes, without limitation, landfill gas, an
anaerobic digester system, 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.
    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 wind energy conversion
systems and the remaining five percent by other eligible energy technology.
    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. 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 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.
History: 2001 c 212 art 8 s 3; 2002 c 398 s 3; 1Sp2003 c 11 art 2 s 3; 2007 c 3 s 1; 2007 c
136 art 4 s 10; art 6 s 1,2
216B.1692 EMISSIONS-REDUCTION RIDER.
    Subdivision 1. Qualifying projects. 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;
(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).
    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; 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, 2013, and applies to plans,
projects, and riders approved before that date and modifications made to them after that date.
History: 1Sp2001 c 5 art 3 s 12; 2006 c 201 s 4
216B.1693 CLEAN ENERGY TECHNOLOGY.
(a) If the commission finds that a clean energy technology is or is likely to be a least-cost
resource, including the costs of ancillary services and other generation and transmission upgrades
necessary, the utility that owns a nuclear generating facility shall supply at least two percent of the
electric energy provided to retail customers from clean energy technology.
(b) Electric energy required by this section shall be supplied by the innovative energy project
defined in section 216B.1694, subdivision 1, unless the commission finds doing so contrary
to the public interest.
(c) For purposes of this section, "clean energy technology" means a 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.
(d) This section expires January 1, 2012.
History: 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 qualify as a "clean energy technology" as defined in section 216B.1693;
(5) 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;
(6) 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;
(7) 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 baseload 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 emission reductions achieved compared to other solid fuel baseload technologies; and
(8) 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.
History: 1Sp2003 c 11 art 4 s 1

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.
History: 1974 c 429 s 17; 1978 c 795 s 4; 1980 c 614 s 113; 1982 c 424 s 130; 1990 c
370 s 4-6
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.
History: 1974 c 429 s 18; 2007 c 10 s 4
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.
History: 1974 c 429 s 19; 1980 c 614 s 114
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.
History: 1974 c 429 s 22; 1980 c 614 s 123
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. 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

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.
History: 1974 c 429 s 24; 1985 c 248 s 70
216B.2401 ENERGY CONSERVATION POLICY GOAL.
    It is the energy policy of the state of Minnesota to achieve annual energy savings equal to
1.5 percent of annual retail energy sales of electricity and natural gas directly through energy
conservation improvement programs and rate design, and indirectly through 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.
History: 2007 c 136 art 2 s 4
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) "Customer facility" means all buildings, structures, equipment, and installations at a
single site.
    (d) "Department" means the Department of Commerce.
    (e) "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.
    (f) "Energy conservation improvement" means a project that results in energy efficiency
or energy conservation. Energy conservation improvement may include waste heat recovery
converted into electricity but does not include electric utility infrastructure projects approved
by the commission under section 216B.1636.
    (g) "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.
     (h) "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 gas sales to a
large energy facility and gas and electric sales to a large electric customer facility exempted by
the commissioner under subdivision 1a, paragraph (b).
    (i) "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.
     (j) "Large electric customer facility" means a customer facility that imposes 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, and
for which electric services are provided at retail on a single bill by a utility operating in the state.
     (k) "Large energy facility" has the meaning given it in section 216B.2421, subdivision 2,
clause (1).
    (l) "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.
    (m) "Low-income programs" means energy conservation improvement programs that
directly serve the needs of low-income persons, including low-income renters.
    (n) "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 electric customer facilities exempted by the commissioner under paragraph (b).
    (b) The owner of a large electric customer facility may petition the commissioner to exempt
both electric and gas utilities serving the large energy customer facility from the investment
and expenditure requirements of paragraph (a) with respect to retail revenues attributable to
the facility. At a minimum, the petition must be supported by evidence relating to competitive
or economic pressures on the customer and a showing by the customer of reasonable efforts to
identify, evaluate, and implement cost-effective conservation improvements at the facility. If a
petition is filed on or before October 1 of any year, the order of the commissioner to exempt
revenues attributable to the facility can be effective no earlier than January 1 of the following
year. The commissioner shall not grant an exemption if the commissioner determines that granting
the exemption is contrary to the public interest. The commissioner may, after investigation,
rescind any exemption granted under this paragraph upon a determination that the customer is not
continuing to make reasonable efforts to identify, evaluate, and implement energy conservation
improvements at the large electric customer facility. For the purposes of investigations by the
commissioner under this paragraph, the owner of any large electric customer facility shall, upon
request, provide the commissioner with updated information comparable to that originally
supplied in or with the owner's original petition under this paragraph.
    (c) 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.
    (d) A public utility or owner of a large electric customer facility may appeal a decision of the
commissioner under paragraph (b) or (c) to the commission under subdivision 2. In reviewing
a decision of the commissioner under paragraph (b) or (c), 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) A municipality may spend up to 50 percent of its required spending under this section
to refurbish an existing district heating or cooling system until July 1, 2007. From July 1, 2007,
through June 30, 2011, expenditures made to refurbish a district heating or cooling system are
considered to be load-management activities under paragraph (e). This paragraph expires July 1,
2011.
    (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.
    (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 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 the
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. 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.
    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
proposed conservation improvement plan under paragraph (a), 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.
    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. 6. Renewable energy research. (a) A public utility that owns a nuclear generation
facility in the state shall spend five percent of the total amount that utility is required to
spend under this section to support basic and applied research and demonstration activities at
the University of Minnesota Initiative for Renewable Energy and the Environment for the
development of renewable energy sources and technologies. The utility shall transfer the required
amount to the University of Minnesota on or before July 1 of each year and that annual amount
shall be deducted from the amount of money the utility is required to spend under this section.
The University of Minnesota shall transfer at least ten percent of these funds to at least one
rural campus or experiment station.
    (b) Activities funded under this subdivision may include, but are not limited to:
    (1) environmentally sound production of energy from a renewable energy source including
biomass;
    (2) environmentally sound production of hydrogen from biomass and any other renewable
energy source for energy storage and energy utilization;
    (3) development of energy conservation and efficient energy utilization technologies;
    (4) energy storage technologies; and
    (5) analysis of policy options to facilitate adoption of technologies that use or produce
low-carbon renewable energy.
    (c) Notwithstanding other law to the contrary, the utility may, but is not required to, spend
more than two percent of its gross operating revenues from service provided in this state under
this section or section 216B.2411.
    (d) For the purposes of this subdivision:
    (1) "renewable energy source" means hydro, wind, solar, biomass and geothermal energy,
and microorganisms used as an energy source; and
    (2) "biomass" means plant and animal material, agricultural and forest residues, mixed
municipal solid waste, and sludge from wastewater treatment.
    (e) This subdivision expires June 30, 2010.
    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 utility that furnishes gas service must spend at least 0.2 percent
of its 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.
    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.
History: 1980 c 579 s 18; 1980 c 614 s 123; 1981 c 356 s 182,248; 1982 c 561 s 4; 1983
c 179 s 6-8; 1989 c 338 s 2,3; 1991 c 235 art 1 s 2; 1992 c 478 s 2,3; 1993 c 249 s 31; 1994 c
483 s 1; 1994 c 641 art 3 s 1; art 4 s 4; 1994 c 644 s 3; 1998 c 273 s 11; 1998 c 350 s 1; 1999 c
140 s 2-7; 2001 c 212 art 8 s 4-7,12; 1Sp2001 c 4 art 6 s 44-46,77; 2003 c 130 s 12; 1Sp2003
c 11 art 2 s 5; art 3 s 4; 2004 c 216 s 3; 2005 c 97 art 7 s 1,2; 2007 c 10 s 5; 2007 c 57 art 2
s 21; 2007 c 136 art 2 s 5
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 that is meeting the objectives under
section 216B.1691 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; or
(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.
(b) For public utilities, as defined under section 216B.02, subdivision 4, projects under this
section must be considered energy conservation improvements as defined in section 216B.241.
For cooperative electric associations and municipal utilities, projects under this section must be
considered load-management activities described in section 216B.241, subdivision 1.
    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),
clause (1), except that the term "biomass" has the meaning provided under paragraph (c).
(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; and
(5) landfill gas, mixed municipal solid waste, and refuse-derived fuel from mixed municipal
solid waste.
    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.
(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.
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.
History: 2001 c 212 art 8 s 13,14; 2002 c 398 s 11; 1Sp2003 c 11 art 2 s 6; 2007 c 136 art
2 s 8
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 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.
History: 2007 c 136 art 2 s 6
216B.242 NATURAL GAS INVERTED RATES PROGRAM.
The commission may initiate a program designed to demonstrate the effect of inverted rates
on promoting conservation by the residential customers of natural gas utilities. Any inverted rates
ordered by the commission shall present customers with a tailblock price that, to the maximum
extent practicable, reflects the replacement cost of gas. Total revenues collected from customers
involved in this pilot program may not exceed those that would be collected under a flat rate. The
commission may order one public gas utility to implement a pilot program of inverted rates for
residential customers and to monitor the effects of these rates on gas consumption, and on costs to
residential customers. The program shall include a sufficient number of residential customers to
provide statistically significant conclusions regarding the effects and costs of inverted rates.
History: 1983 c 289 s 115 subd 1; 1983 c 301 s 172; 1987 c 312 art 1 s 26 subd 2; 1993 c
163 art 1 s 27
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]
History: 1974 c 307 s 2; 1975 c 170 s 1; 1977 c 381 s 8; Ex1979 c 2 s 11; 1981 c 356 s
248; 1982 c 561 s 1; 1991 c 199 art 2 s 1; 1993 c 327 s 8,9; 1993 c 356 s 2; 2001 c 212 art
7 s 29; 2005 c 97 art 1 s 4
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; or
(6) landfill gas.
(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. 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.
    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.
History: 1993 c 356 s 3; 1994 c 644 s 4; 1997 c 176 s 2; 1997 c 198 s 1
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.
History: 1994 c 641 art 3 s 2; 1997 c 216 s 123; 1999 c 200 s 3
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 biomass, as defined in section 216C.051, subdivision
7
, 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 Minnesota jurisdictional portion of 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.
    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.
History: 1994 c 641 art 3 s 3; 1995 c 224 s 76; 1996 c 450 s 1; 1998 c 345 s 2; 2000 c 443 s
1-5; 2001 c 7 s 46; 1Sp2001 c 5 art 3 s 13; 2002 c 379 art 1 s 55; 2003 c 127 art 2 s 3; 1Sp2003 c
11 art 2 s 7,16; 2005 c 97 art 5 s 1-6; 1Sp2005 c 1 art 2 s 140; 2006 c 259 art 4 s 4
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.
(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) Transmission projects determined by the commission to be necessary to support a
utility's plan under section 216B.1691 to meet its obligations under that section must be certified
as a priority electric transmission project, satisfying the requirements of section 216B.243. In
determining that a proposed transmission project is necessary to support a utility's plan under
section 216B.1691, the commission must find that the applicant has met the following factors:
(1) that the transmission facility is necessary to allow the delivery of power from renewable
sources of energy to retail customers in Minnesota;
(2) that the applicant has signed or will sign power purchase agreements, subject to
commission approval, for resources to meet the renewable energy objective that are dependent
upon or will use the capacity of the transmission facility to serve retail customers in Minnesota;
(3) that the installation and commercial operation date of the renewable resources to satisfy
the renewable energy objective will match the planned in-service date of the transmission facility;
and
(4) that the proposed transmission facility is consistent with a least-cost solution to the
utility's need for additional electricity.
History: 2001 c 212 art 7 s 30; 2002 c 379 art 1 s 56; 1Sp2003 c 11 art 2 s 8; 2005 c
97 art 1 s 7; art 2 s 3

NOTE:Subdivision 7, paragraph (b), as added by Laws 2005, chapter 97, article 2, section
3, expires January 1, 2010. Laws 2005, chapter 97, article 2, section 7.
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.
History: 2005 c 97 art 8 s 1
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;
(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; or
(7) a large energy facility that (i) generates electricity from wind energy conversion systems,
(ii) will serve retail customers in Minnesota, (iii) is specifically intended to be used to meet the
renewable energy objective under section 216B.1691 or addresses a resource need identified in a
current commission-approved or commission-reviewed resource plan under section 216B.2422,
and (iv) derives at least ten percent of the total nameplate capacity of the proposed project from
one or more C-BED projects, as defined under section 216B.1612, subdivision 2, paragraph (f).
History: 1974 c 307 s 13; 1975 c 170 s 3,4; 1977 c 381 s 19; Ex1979 c 2 s 32; 1980 c 579 s
10,11; 1980 c 614 s 123; 1981 c 356 s 159,248; 1982 c 424 s 130; 1982 c 561 s 2; 1983 c 289 s
46,115 subd 2; 1984 c 558 art 4 s 10; 1984 c 655 art 1 s 22,23; 1985 c 304 s 1; 1987 c 312 art 1 s
10 subd 1; 1991 c 235 art 4 s 1; art 6 s 2; 1994 c 641 art 2 s 2; 2001 c 212 art 7 s 31-33; 2002 c
398 s 4; 1Sp2003 c 11 art 1 s 4; 2005 c 97 art 1 s 5,6; art 2 s 4; art 3 s 13-15
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.
History: 1994 c 641 art 2 s 3
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

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.
History: 1974 c 429 s 26; 2007 c 10 s 6
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.
History: 1974 c 429 s 27; 1995 c 224 s 77
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.
History: 1974 c 429 s 33; 2007 c 10 s 7
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.
History: 1974 c 429 s 36; 1978 c 795 s 5; 1Sp1981 c 1 art 6 s 8; 1982 c 378 s 1; 1991
c 291 art 9 s 4

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.
History: 1Sp2003 c 11 art 3 s 5

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.
History: 1974 c 429 s 38; 1978 c 795 s 6
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.
History: 1974 c 429 s 40; 1977 c 99 s 1
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.
History: 1974 c 429 s 43; 1993 c 327 s 10

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.
History: 1974 c 429 s 44; 1983 c 301 s 173
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.
History: 1974 c 429 s 45; 1978 c 795 s 7
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.
History: 1974 c 429 s 47; 1978 c 795 s 8; 1994 c 610 s 1

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]
History: 1974 c 429 s 48; 1993 c 327 s 11-13
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 shall be 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 shall first be approved by the commission. Approval by the commission shall
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.
History: 1974 c 429 s 49; 1982 c 378 s 2; 1983 c 167 s 1; 1985 c 248 s 70; 1987 c 291 s
203; 1998 c 350 s 2,3
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.
History: 1974 c 429 s 50; 2005 c 97 art 1 s 8
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]
History: 1974 c 429 s 52; 1978 c 674 s 60; 1983 c 247 s 96
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.
History: 1974 c 429 s 53; 1977 c 364 s 6
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.
History: 1974 c 429 s 54; 1980 c 614 s 115
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.
History: 1974 c 429 s 61; 2005 c 10 art 1 s 34

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 and section 216A.085 (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 (1) public utilities under section 216A.085, sections
216B.01 to 216B.67, other than amounts chargeable to public utilities under subdivision 2 or 6,
and (2) alternative energy engineering activity under section 216C.261. The remainder, except
the amount assessed against cooperatives and municipalities for alternative energy engineering
activity under subdivision 5, 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. 4. Objections. Within 30 days after the date of the transmittal of any bill as provided
by subdivisions 2 and 3, 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.
The department shall assess cooperatives and municipalities for the costs of alternative
energy engineering activities under section 216C.261. Each cooperative and municipality shall be
assessed in proportion that its gross operating revenues 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. 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.
History: 1974 c 429 s 62 subds 1-4; 1978 c 674 s 60; 1978 c 795 s 9; 1980 c 614 s 116;
1981 c 357 s 71,72; 1983 c 289 s 105,106; 1990 c 598 s 1; 1991 c 234 s 2; 1992 c 478 s 4; 1993 c
356 s 4; 1993 c 369 s 66,67; 2001 c 212 art 7 s 34; 2005 c 97 art 1 s 9,10; 2007 c 10 s 8-10
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.
History: 1974 c 429 s 63; 2007 c 10 s 11

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 EMISSION 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 emission-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 EMISSION-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, 2014.
    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. 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, 2011, to file its plans for
reduction at its other wet scrubbed unit at the qualifying facility, and may have until December
31, 2014, to implement mercury emissions reduction at that unit.
    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, 2014, 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.
History: 2006 c 201 s 11
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. Emission-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.
History: 2001 c 212 art 3 s 2; 2005 c 97 art 1 s 11
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.
History: 1Sp2003 c 11 art 2 s 2
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.
History: 2005 c 97 art 13 s 1; 1Sp2005 c 1 art 4 s 119
216B.812 FOSTERING USE OF HYDROGEN ENERGY.
    Subdivision 1. Early purchase and deployment of renewable hydrogen, fuel cells, and
related technologies by the state. (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.
History: 2005 c 97 art 13 s 2; 1Sp2005 c 1 art 4 s 120; 2007 c 57 art 2 s 17,22
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.013. 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.
History: 2007 c 57 art 2 s 23
216B.815 REGIONAL ENERGY RESEARCH AND EDUCATION PARTNERSHIP;
GOALS.
(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.
History: 2005 c 97 art 13 s 3

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.
History: 2005 c 97 art 8 s 2