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HF 239

1st Engrossment - 92nd Legislature (2021 - 2022) Posted on 05/10/2021 04:51pm

KEY: stricken = removed, old language.
underscored = added, new language.

Current Version - 1st Engrossment

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A bill for an act
relating to energy; establishing the Natural Gas Innovation Act; encouraging natural
gas utilities to develop innovative resources; requiring reports; appropriating
money; proposing coding for new law in Minnesota Statutes, chapter 216B.

BE IT ENACTED BY THE LEGISLATURE OF THE STATE OF MINNESOTA:

Section 1. new text beginTITLE.
new text end

new text begin This bill may be referred to as the "Natural Gas Innovation Act."
new text end

new text begin EFFECTIVE DATE. new text end

new text begin This section is effective the day following final enactment.
new text end

Sec. 2.

new text begin [216B.2427] NATURAL GAS UTILITY INNOVATION PLANS.
new text end

new text begin Subdivision 1. new text end

new text begin Definitions. new text end

new text begin (a) For the purposes of this section and section 216B.2428,
the following terms have the meanings given.
new text end

new text begin (b) "Biogas" means gas produced by the anaerobic digestion of biomass, gasification of
biomass, or other effective conversion processes.
new text end

new text begin (c) "Carbon capture" means the capture of greenhouse gas emissions that would otherwise
be released into the atmosphere.
new text end

new text begin (d) "Carbon-free resource" means an electricity generation facility whose operation does
not contribute to statewide greenhouse gas emissions, as defined in section 216H.01,
subdivision 2.
new text end

new text begin (e) "District energy" means a heating or cooling system that is solar thermal powered
or that uses the constant temperature of the earth or underground aquifers as a thermal
exchange medium to heat or cool multiple buildings connected through a piping network.
new text end

new text begin (f) "Energy efficiency" has the meaning given in section 216B.241, subdivision 1,
paragraph (f), but does not include energy conservation investments that the commissioner
determines could reasonably be included in a utility's conservation improvement program.
new text end

new text begin (g) "Greenhouse gas emissions" means emissions of carbon dioxide, methane, nitrous
oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride emitted by
anthropogenic sources within the state and from the generation of electricity imported from
outside Minnesota and consumed in Minnesota. Greenhouse gas emissions does not include
carbon dioxide that is injected into geological formations to prevent the carbon dioxide's
release to the atmosphere in compliance with applicable laws.
new text end

new text begin (h) "Innovative resource" means biogas, renewable natural gas, power-to-hydrogen,
power-to-ammonia, carbon capture, strategic electrification, district energy, and energy
efficiency.
new text end

new text begin (i) "Lifecycle greenhouse gas emissions" means the aggregate greenhouse gas emissions
resulting from the production, processing, transmission, and consumption of an energy
resource.
new text end

new text begin (j) "Lifecycle greenhouse gas emissions intensity" means lifecycle greenhouse gas
emissions per unit of energy.
new text end

new text begin (k) "Nonexempt customer" means a utility customer that has not been included in a
utility's innovation plan under subdivision 3, paragraph (f).
new text end

new text begin (l) "Power-to-ammonia" means the production of ammonia from hydrogen produced
via power-to-hydrogen using a process that has a lower lifecycle greenhouse gas intensity
than does natural gas produced from conventional geologic sources.
new text end

new text begin (m) "Power-to-hydrogen" means the use of electricity generated by a carbon-free resource
to produce hydrogen.
new text end

new text begin (n) "Renewable energy" has the meaning given in section 216B.2422, subdivision 1.
new text end

new text begin (o) "Renewable natural gas" means biogas that has been processed to be interchangeable
with, and that has a lower lifecycle greenhouse gas intensity than, natural gas produced
from conventional geologic sources.
new text end

new text begin (p) "Solar thermal" has the meaning given to "qualifying solar thermal project" in section
216B.2411, subdivision 2, paragraph (d).
new text end

new text begin (q) "Strategic electrification" means the installation of electric end-use equipment in an
existing building in which natural gas is a primary or back-up fuel source or in a
newly-constructed building in which a customer receives natural gas service for one or more
end-uses, provided that the electric end-use equipment:
new text end

new text begin (1) results in a net reduction in statewide greenhouse gas emissions, as defined in section
216H.01, subdivision 2, over the life of the equipment when compared to the most efficient
commercially available natural gas alternative; and
new text end

new text begin (2) is installed and operated in a manner that improves the load factor of the customer's
electric utility.
new text end

new text begin Strategic electrification does not include investments that the commissioner determines
could reasonably be included in the natural gas utility's conservation improvement program
under section 216B.241.
new text end

new text begin (r) "Total incremental cost" means the sum of the following components of a utility's
innovation plan approved by the commission under subdivision 2:
new text end

new text begin (1) return of and on capital investments for the production, processing, pipeline
interconnection, storage, and distribution of innovative resources;
new text end

new text begin (2) incremental operating costs associated with capital investments in infrastructure for
the production, processing, pipeline interconnection, storage, and distribution of innovative
resources;
new text end

new text begin (3) incremental costs to procure innovative resources from third parties;
new text end

new text begin (4) incremental costs to develop and administer programs; and
new text end

new text begin (5) incremental costs for research and development related to innovative resources, less
the sum of:
new text end

new text begin (i) value received by the utility upon the resale of innovative resources or the innovative
resources' byproducts, including any environmental credits included with the resale of
renewable gaseous fuels or value received by the utility when innovative resources are used
as vehicle fuel;
new text end

new text begin (ii) cost savings achieved through avoidance of purchases of natural gas produced from
conventional geologic sources, including but not limited to avoided commodity purchases
or avoided pipeline costs; and
new text end

new text begin (iii) other revenues received by the utility that are directly attributable to the utility's
implementation of an innovation plan.
new text end

new text begin (s) "Utility" means a public utility as defined in section 216B.02, subdivision 4, that
provides natural gas sales or natural gas transportation services to customers in Minnesota.
new text end

new text begin Subd. 2. new text end

new text begin Innovation plans. new text end

new text begin (a) A natural gas utility may file an innovation plan with
the commission. The utility's plan must include, as applicable, the following components:
new text end

new text begin (1) the innovative resource or resources the utility plans to implement to contribute to
meeting the state's greenhouse gas and renewable energy goals, including those established
in sections 216C.05, subdivision 2, clause (3), and 216H.02, subdivision 1, within the
requirements and limitations set forth in this section;
new text end

new text begin (2) research and development investments related to innovative resources the utility
plans to undertake;
new text end

new text begin (3) total lifecycle greenhouse gas emissions that the utility projects are reduced or avoided
through implementing the plan;
new text end

new text begin (4) a comparison of the estimate in clause (3) to total emissions from natural gas use by
utility customers in 2020;
new text end

new text begin (5) a description of each pilot program included in the plan that is related to the
development or provision of innovative resources, and an estimate of the total incremental
costs to implement each element;
new text end

new text begin (6) the cost-effectiveness of innovative resources, calculated from the perspective of the
utility, society, the utility's nonparticipating customers, and the utility's participating
customers, compared to other innovative resources that could be deployed to reduce or
avoid the same greenhouse gas emissions targeted for reduction by the utility's proposed
innovative resource;
new text end

new text begin (7) for any pilot program not previously approved as part of the utility's most recent
innovation plan, a third-party analysis of:
new text end

new text begin (i) the lifecycle greenhouse gas emissions intensity of the proposed innovative resources;
and
new text end

new text begin (ii) the forecasted lifecycle greenhouse gas emissions reduced or avoided if the proposed
pilot program is implemented;
new text end

new text begin (8) an explanation of the methodology used by the utility to calculate the lifecycle
greenhouse gas emissions avoided or reduced by each pilot program included in the plan,
including descriptions of how the utility's method deviated, if at all, from the carbon
accounting frameworks established by the commission under section 216B.2428;
new text end

new text begin (9) a discussion of whether the plan supports the development and use of alternative
agricultural products, waste reduction, reuse, or anaerobic digestion of organic waste, and
the recovery of energy from wastewater, and if it does, a description of the geographic areas
of the state in which those benefits will be realized;
new text end

new text begin (10) a description of third-party systems and processes the utility plans to use to:
new text end

new text begin (i) track the innovative resources included in the plan so that environmental benefits
produced by the plan are not claimed for any other program; and
new text end

new text begin (ii) verify the environmental attributes and greenhouse gas emissions intensity of
innovative resources included in the plan;
new text end

new text begin (11) projected local job impacts resulting from implementation of the plan and a
description of steps the utility and the utility's energy suppliers and contractors are taking
to maximize the availability of construction employment opportunities for local workers;
new text end

new text begin (12) a description of how the utility proposes to recover annual total incremental costs
of the plan;
new text end

new text begin (13) steps the utility has taken or proposes to take to reduce the expected cost of the plan
on low- and moderate-income residential customers and to ensure that low- and
moderate-income residential customers benefit from innovative resources included in the
plan;
new text end

new text begin (14) a report on the utility's progress toward implementing its previously approved
innovation plan, if applicable;
new text end

new text begin (15) a report of the utility's progress toward achieving the cost-effectiveness objectives
established by the commission with respect to the utility's previously approved innovation
plan, if applicable; and
new text end

new text begin (16) collections of pilot programs that the utility estimates would, if implemented, provide
approximately 50 percent, 150 percent, and 200 percent of the greenhouse gas reduction or
avoidance benefits of the utility's proposed plan.
new text end

new text begin (b) The commission must approve, modify, or reject a plan. The commission must not
approve an innovation plan unless the commission finds that:
new text end

new text begin (1) the size, scope, and scale of the plan produces net benefits under the cost-benefit
framework established by the commission in section 216B.2428;
new text end

new text begin (2) the plan promotes the use of renewable energy resources and reduce or avoid
greenhouse gas emissions at a cost level consistent with subdivision 3;
new text end

new text begin (3) the plan promotes local economic development;
new text end

new text begin (4) the innovative resources included in the plan have a lower lifecycle greenhouse gas
intensity than natural gas produced from conventional geologic sources;
new text end

new text begin (5) the systems used to track and verify the environmental attributes of the innovative
resources included in the plan are reasonable, considering available third-party tracking and
verification systems;
new text end

new text begin (6) the costs and revenues projected under the plan are reasonable in comparison to other
innovative resources the utility could deploy to reduce greenhouse gas emissions, considering
other benefits of the innovative resources included in the plan;
new text end

new text begin (7) the total amount of estimated greenhouse gas emissions reduction or avoidance to
be achieved under the plan is reasonable considering the state's greenhouse gas and renewable
energy goals, including those established in section 216C.05, subdivision 2, clause (3), and
section 216H.02, subdivision 1, customer cost, and the total amount of greenhouse gas
emissions reduction or avoidance achieved under the utility's previously approved plans, if
applicable; and
new text end

new text begin (8) any renewable natural gas purchased by a utility under the plan that is produced from
the anaerobic digestion of manure is certified as being produced at an agricultural livestock
production facility that does not increase the number of animal units at the facility solely
or primarily for the purpose of producing renewable natural gas for the plan.
new text end

new text begin (c) In seeking to recover costs under a plan approved by the commission under this
section, the utility must demonstrate to the satisfaction of the commission that the actual
total incremental costs incurred to implement the approved innovation plan are reasonable.
Prudently incurred costs under an approved plan, including prudently incurred costs to
obtain the third-party analysis required in paragraph (a), clauses (6) and (7), are recoverable
either:
new text end

new text begin (1) under section 216B.16, subdivision 7, clause (2), via the utility's purchased gas
adjustment;
new text end

new text begin (2) in the utility's next general rate case; or
new text end

new text begin (3) via annual adjustments, provided that after notice and comment the commission
determines that the costs included for recovery through rates are prudently incurred. Annual
adjustments must include a rate of return, income taxes on the rate of return, incremental
property taxes, incremental depreciation expense, and incremental operation and maintenance
expenses. The rate of return must be at the level approved by the commission in the utility's
last general rate case unless the commission determines that a different rate of return is in
the public interest.
new text end

new text begin (d) Upon approval of a utility's plan, the commission shall establish cost-effectiveness
objectives for the plan based on the cost-benefit test for innovative resources developed
under section 216B.2428. The cost-effectiveness objective for each plan must demonstrate
incremental progress from the previously approved plan's cost-effectiveness objective.
new text end

new text begin (e) A utility operating under an approved plan must file annual reports to the commission
on work completed under the plan, including:
new text end

new text begin (1) costs incurred;
new text end

new text begin (2) lifecycle greenhouse gas emissions reductions or avoidance achieved;
new text end

new text begin (3) a description of the processes used to track and verify the innovative resources and
to retire the associated environmental attributes;
new text end

new text begin (4) an assessment of the degree to which the lifecycle greenhouse gas accounting
methodology is consistent with current science;
new text end

new text begin (5) the economic impact of the plan, including job creation;
new text end

new text begin (6) the utility's progress toward achieving the cost-effectiveness objectives established
by the commission; and
new text end

new text begin (7) modifications to elements of the plan proposed by the utility.
new text end

new text begin (f) In evaluating a utility's annual report, the commission may:
new text end

new text begin (1) approve the continuation of a pilot program included in the plan, with or without
modifications;
new text end

new text begin (2) require the utility to file a new or modified pilot program or plan; or
new text end

new text begin (3) disapprove the continuation of a pilot program or plan.
new text end

new text begin (g) An innovation plan has a term of five years. A subsequent innovation plan must be
filed no later than four years after the previous plan was approved by the commission, so
that if approved the new plan takes effect immediately upon expiration of the previous plan.
new text end

new text begin (h) For purposes of this section and the commission's lifecycle carbon accounting
framework and cost-benefit test for innovative resources under section 216B.2428, any
required analysis of lifecycle greenhouse gas emissions reductions or avoidance, or lifecycle
greenhouse gas intensity:
new text end

new text begin (1) must include but is not limited to estimates of:
new text end

new text begin (i) avoided or reduced greenhouse gas emissions attributable to utility operations;
new text end

new text begin (ii) avoided or reduced greenhouse gas emissions from the production, processing, and
transmission of fuels prior to the fuels' receipt by the utility; and
new text end

new text begin (iii) avoided or reduced greenhouse gas emissions at the point of end use;
new text end

new text begin (2) must not count any unit of greenhouse gas emissions avoidance or reduction more
than once; and
new text end

new text begin (3) may, where direct measurement is not technically or economically feasible, rely on
emissions factors, default values, or engineering estimates from a publicly accessible source
accepted by a federal or state government agency, provided that the utility demonstrates to
the commission's satisfaction that the emissions factors, default values, or engineering
estimates produce a reasonable estimate of greenhouse gas emissions reductions, avoidance,
or intensity.
new text end

new text begin (i) Strategic electrification implemented in a plan approved by the commission under
this section is not eligible for a financial incentive under section 216B.241, subdivision 2c.
Electric end-use equipment installed under a plan approved by the commission under this
section is the exclusive property of the building owner.
new text end

new text begin Subd. 3. new text end

new text begin Limitations on utility customer costs. new text end

new text begin (a) Except as provided in paragraph
(b), the first innovation plan submitted to the commission by a utility must not propose, and
the commission must not approve, annual total incremental costs exceeding the lesser of:
new text end

new text begin (1) 1.75 percent of the utility's gross operating revenues from natural gas service provided
in Minnesota at the time of plan filing; or
new text end

new text begin (2) $20 per nonexempt customer based on the proposed annual total incremental costs
for each year of the plan divided by the total number of nonexempt utility customers.
new text end

new text begin (b) The commission may approve additional annual costs up to the lesser of:
new text end

new text begin (1) an additional 0.25 percent of the utility's gross operating revenues from service
provided in Minnesota at the time of plan filing; or
new text end

new text begin (2) $5 per nonexempt customer, based on the proposed annual total incremental costs
for each year of the plan divided by the total number of nonexempt utility customers of
incremental costs, provided that the additional costs under this paragraph are associated
exclusively with the purchase of renewable natural gas produced from:
new text end

new text begin (i) food waste diverted from a landfill;
new text end

new text begin (ii) a municipal wastewater treatment system; or
new text end

new text begin (iii) an organic mixture including at least 15 percent, by volume, sustainably harvested
native prairie grasses or locally appropriate cover crops, as determined by a local soil and
water conservation district or the United States Department of Agriculture, Natural Resources
Conservation Service.
new text end

new text begin (c) If the commission determines that the utility has successfully achieved the
cost-effectiveness objectives established in the utility's most recently approved innovation
plan, except as provided in paragraph (d), the next plan filed by the same utility under this
section is subject to the provisions of paragraphs (a) and (b), except that:
new text end

new text begin (1) the cap on total incremental costs in paragraph (a) with respect to the second plan is
the lesser of:
new text end

new text begin (i) 2.75 percent of the utility's gross operating revenues from natural gas service in
Minnesota at the time of the plan's filing; or
new text end

new text begin (ii) $35 per nonexempt customer; and
new text end

new text begin (2) the cap on additional costs in paragraph (b) is the lesser of:
new text end

new text begin (i) an additional 0.75 percent of the utility's gross operating revenues from natural gas
service in Minnesota at the time of the plan's filing; or
new text end

new text begin (ii) $10 per nonexempt customer.
new text end

new text begin (d) If the commission determines that the utility has successfully achieved the
cost-effectiveness objectives established in two of the same utility's previously approved
innovation plans, all subsequent plans filed by the utility under this section are subject to
the provisions of paragraphs (a) and (b), except that:
new text end

new text begin (1) the cap on total incremental costs in paragraph (a) with respect to the third or
subsequent plan is the lesser of:
new text end

new text begin (i) four percent of the utility's gross operating revenues from natural gas service in
Minnesota at the time of the plan's filing; or
new text end

new text begin (ii) $50 per nonexempt customer; and
new text end

new text begin (2) the cap on additional costs in paragraph (b) is the lesser of:
new text end

new text begin (i) an additional 1.5 percent of the utility's gross operating revenues from natural gas
service in Minnesota at the time of the plan's filing; or
new text end

new text begin (ii) $20 per nonexempt customer.
new text end

new text begin (e) For purposes of paragraphs (a) to (d), the limits on annual total incremental costs
must be calculated at the time the innovation plan is filed as the average of the utility's
forecasted total incremental costs over the five-year term of the plan.
new text end

new text begin (f) A large customer facility that has been exempted by the commissioner of commerce
from a utility's conservation improvement program under section 216B.241, subdivision
1a, paragraph (b), is exempt from the utility's innovation plan offerings and must not be
charged any costs incurred to implement an approved innovation plan unless the large
customer facility files a request with the commissioner to be included in a utility's innovation
plan. The commission may prohibit large customer facilities exempted from innovation
plan costs from participating in innovation plans.
new text end

new text begin (g) A utility filing an innovation plan may include annual spending and investments on
research and development of up to ten percent of the proposed total incremental costs related
to innovation plans, subject to the limitations in paragraphs (a) to (e).
new text end

new text begin (h) For purposes of this subdivision, "gross operating revenues" do not include revenues
from large customer facilities exempted from innovation plan costs.
new text end

new text begin Subd. 4. new text end

new text begin Innovative resources procured outside of an innovation plan. new text end

new text begin (a) Without
filing an innovation plan, a natural gas utility may propose and the commission may approve
cost recovery for:
new text end

new text begin (1) innovative resources acquired to satisfy a commission-approved green tariff program
that allows customers to choose to meet a portion of the customers' energy needs through
innovative resources; or
new text end

new text begin (2) utility expenditures for innovative resources procured at a cost that is within five
percent of the average of Ventura and Demarc index prices for natural gas produced from
conventional geologic sources at the time of the transaction per unit of natural gas that the
innovative resource displaces.
new text end

new text begin (b) An approved green tariff program must include provisions to ensure that reasonable
systems are used to track and verify the environmental attributes of innovative resources
included in the program, taking into account any available third party tracking or verification
systems.
new text end

new text begin (c) For the purposes of this subdivision, "Ventura and Demarc index prices" means the
daily index price of wholesale natural gas sold at the Northern Natural Gas Company's
Ventura trading hub in Hancock County, Iowa, and its demarcation point in Clifton, Kansas.
new text end

new text begin Subd. 5. new text end

new text begin Power-to-ammonia. new text end

new text begin In determining whether to approve a power-to-ammonia
pilot program as part of an innovation plan, the commission must consider:
new text end

new text begin (1) the risk of exposing any person to unhealthy concentrations of ammonia;
new text end

new text begin (2) the risk that any home or business might be affected by ammonia odors;
new text end

new text begin (3) whether the greenhouse gas emissions addressed by the proposed power-to-ammonia
project could be more efficiently addressed using power-to-hydrogen; and
new text end

new text begin (4) whether the power-to-ammonia project achieves lifecycle greenhouse gas emissions
reductions in the agricultural sector more effectively than power-to-hydrogen.
new text end

new text begin Subd. 6. new text end

new text begin Thermal energy audits. new text end

new text begin The first innovation plan filed under this section by
a utility with more than 800,000 customers must include a pilot program to provide thermal
energy audits to small and medium-sized businesses in order to identify opportunities to
reduce or avoid greenhouse gas emissions from natural gas use. The pilot program must
provide incentives for businesses to implement recommendations made by the audit. The
utility must develop criteria to identify businesses that achieve significant emissions
reductions by implementing audit recommendations and must recognize the businesses as
thermal energy leaders.
new text end

new text begin Subd. 7. new text end

new text begin Innovative resources for certain industrial processes. new text end

new text begin The first innovation
plan filed under this section by a utility with more than 800,000 customers must include a
pilot program to provide innovative resources to industrial facilities whose manufacturing
processes, for technical reasons, are not amenable to electrification. A large customer facility
exempt from innovation plan offerings under subdivision 3, paragraph (f), is not eligible to
participate in the pilot program.
new text end

new text begin Subd. 8. new text end

new text begin Electric cold climate air-source heat pumps. new text end

new text begin (a) The first innovation plan
filed under this section by a utility with more than 800,000 customers must include a pilot
program that facilitates deep energy retrofits and the installation of cold climate electric
air-source heat pumps in existing residential homes that have natural gas heating systems.
new text end

new text begin (b) For purposes of this subdivision, "deep energy retrofit" means the installation of any
measure or combination of measures, including air sealing and addressing thermal bridges,
that under normal weather and operating conditions can reasonably be expected to reduce
a building's calculated design load to ten or fewer British Thermal Units per hour per square
foot of conditioned floor area. Deep energy retrofit does not include the installation of
photovoltaic electric generation equipment, but may include the installation of a qualifying
solar thermal energy project.
new text end

new text begin Subd. 9. new text end

new text begin District energy. new text end

new text begin The first innovation plan filed under this section by a utility
with more than 800,000 customers must include a pilot program to facilitate the development,
expansion, or modification of district energy systems in Minnesota. This subdivision does
not require the utility to propose, construct, maintain, or own district energy infrastructure.
new text end

new text begin Subd. 10. new text end

new text begin Throughput goal. new text end

new text begin It is the goal of the state of Minnesota that through the
Natural Gas Innovation Act and Conservation Improvement Program, utilities reduce the
overall amount of natural gas produced from conventional geologic sources delivered to
customers.
new text end

new text begin Subd. 11. new text end

new text begin Utility system report and forecasts. new text end

new text begin (a) A public utility filing an innovation
plan shall concurrently submit a report to the commission containing the following
information:
new text end

new text begin (1) methane gas emissions attributed to venting or leakage across the utility's system,
including emissions information reported to the Environmental Protection Agency and gas
leaks considered to be hazardous or nonhazardous, and a narrative description of the utility's
expectations regarding the cost and performance of the utility's leakage reduction programs
over the next five years;
new text end

new text begin (2) total system greenhouse gas emissions and greenhouse gas emissions projected to
be reduced or avoided through innovative resource investments and energy conservation
investments, and a narrative description of the costs required to achieve the reduction or
avoidance over the next five years through investments in innovative sources and energy
conservation;
new text end

new text begin (3) the quantity of pipe in service in the utility's natural gas network in Minnesota, by
material, size, coating, operating pressure, and decade of installation based on utility
information reported to the U.S. Department of Transportation;
new text end

new text begin (4) a narrative description of other significant equipment owned and operated by the
utility through which gas is transported or stored, including regulator stations and storage
facilities, a discussion of the function of that equipment, how the equipment is maintained,
and utility efforts to prevent leaks from the equipment;
new text end

new text begin (5) a five-year forecast of fuel prices and anticipated purchases including, as available,
natural gas produced from conventional geologic sources, renewable natural gas, and
alternative fuels;
new text end

new text begin (6) a five-year forecast of potential capital investments by the utility in existing
infrastructure and new infrastructure for natural gas produced from conventional geologic
sources and for innovative resources; and
new text end

new text begin (7) an inventory of the utility's current financial incentive programs for natural gas,
including rebates and incentives offered for new and existing buildings and a description
of the utility's projected changes in incentives the utility is likely to implement over the next
five years.
new text end

new text begin (b) Information filed under this subdivision is intended to be used by the commission
to evaluate a utility's innovation plan in the context of the utility's other planned investments
and activities with respect to natural gas produced from conventional geologic sources.
Information filed under this subdivision must not be used by the commission to set or limit
utility rate recovery.
new text end

new text begin Subd. 12. new text end

new text begin Annual legislative report. new text end

new text begin A utility whose innovation plan has been approved
by the commission under this section must, beginning one year after commission approval
of the plan and continuing each year thereafter, submit to the chairs and ranking minority
members of the senate and house of representatives committees with primary jurisdiction
over energy policy a report that contains the following information:
new text end

new text begin (1) the lifecycle greenhouse gas emissions and lifecycle greenhouse gas emissions
intensity of the utility's natural gas operations in Minnesota in 2020;
new text end

new text begin (2) the lifecycle greenhouse gas emissions and lifecycle greenhouse gas emissions
intensity of each of the pilot programs the utility has implemented under an approved
innovation plan during the previous 12 months; and
new text end

new text begin (3) an estimate of the social cost of the lifecycle greenhouse gas emissions in clauses
(1) and (2), utilizing the most recent methodology used by the federal Environmental
Protection Agency to measure the social cost of greenhouse gas emissions and employing
a discount rate no greater than three percent.
new text end

new text begin EFFECTIVE DATE. new text end

new text begin This section is effective June 1, 2022.
new text end

Sec. 3.

new text begin [216B.2428] PUBLIC UTILITIES COMMISSION; LIFECYCLE
GREENHOUSE GAS EMISSIONS ACCOUNTING FRAMEWORK; COST-BENEFIT
TEST FOR INNOVATIVE RESOURCES.
new text end

new text begin By June 1, 2022, the Public Utilities Commission shall, by order, issue frameworks the
commission must use to calculate lifecycle greenhouse gas emissions intensities of each
innovative resource, as follows:
new text end

new text begin (1) a general framework for the comparison of the lifecycle greenhouse gas emissions
intensities of power-to-hydrogen, strategic electrification, renewable natural gas, district
energy, energy efficiency, biogas, carbon capture, and power-to-ammonia; and
new text end

new text begin (2) a cost-benefit analytic framework to be applied to innovative resources and innovation
plans filed under section 216B.2427 that the commission must use to compare the
cost-effectiveness of those resources and plans. This analytic framework must take into
account:
new text end

new text begin (i) the total incremental cost of the plan or resource and the lifecycle greenhouse gas
emissions avoided or reduced by the innovative resource or plan, using the framework
developed under clause (1);
new text end

new text begin (ii) additional economic costs and benefits, programmatic costs and benefits, additional
environmental costs and benefits, and other costs or benefits that may be expected under a
plan; and
new text end

new text begin (iii) baseline cost-effectiveness criteria against which an innovation plan should be
compared. In establishing baseline criteria, the commission must take into account options
available to reduce lifecycle greenhouse gas emissions from natural gas end uses and the
goals in sections 216C.05, subdivision 2, clause (3), and 216H.02, subdivision 1. To the
maximum reasonable extent, the cost-benefit framework must be consistent with
environmental cost values established under section 216B.2422, subdivision 3, and other
calculations of the social value of greenhouse gas emissions reductions used by the
commission. The commission may update frameworks established under this section as
necessary.
new text end

new text begin EFFECTIVE DATE. new text end

new text begin This section is effective the day following final enactment.
new text end

Sec. 4. new text beginPUBLIC UTILITIES COMMISSION; EVALUATION OF THE ROLE OF
NATURAL GAS UTILITIES IN ACHIEVING STATE GREENHOUSE GAS
REDUCTION GOALS.
new text end

new text begin By August 1, 2021, the Public Utilities Commission must initiate a proceeding to evaluate
changes to natural gas utility regulatory and policy structures needed to support the state's
greenhouse gas emissions reductions goals, including those established in section 216H.02,
subdivision 1, and to achieve net zero greenhouse gas emissions by 2050, as determined by
the Intergovernmental Panel on Climate Change.
new text end

new text begin EFFECTIVE DATE. new text end

new text begin This section is effective the day following final enactment.
new text end

Sec. 5. new text beginAPPROPRIATION.
new text end

new text begin $189,000 in fiscal year 2022 and $189,000 in fiscal year 2023 are appropriated from the
general fund to the commissioner of commerce for the work identified under Minnesota
Statutes, section 216B.2427. This appropriation must be recovered under the Department
of Commerce's assessment authority under Minnesota Statutes, section 216B.62.
new text end

new text begin EFFECTIVE DATE. new text end

new text begin This section is effective the day following final enactment.
new text end