1.1 	A bill for an act
1.2 	relating to energy; removing obsolete language;amending Minnesota Statutes 
1.3 	2018, sections 216B.16, subdivisions 6b, 19; 216B.1645, subdivision 1; 216B.2422, 
1.4 	subdivision 5; 272.0211, subdivision 1; 282.04, subdivision 1, by adding 
1.5 	subdivisions; repealing Minnesota Statutes 2018, sections 116C.705; 116C.71, 
1.6 	subdivisions 1a, 1b, 2c, 3a; 116C.711; 116C.77; 116C.771; 116C.773; 216B.1611; 
1.7 	216B.1613; 216B.1646; 216B.1675, subdivision 13; 216B.1681; 216B.1691, 
1.8 	subdivisions 2, 2d; 216B.1695; 216B.2423; 216B.2424; 216H.02, subdivisions 2, 
1.9 	3, 4, 5, 6; 272.02, subdivisions 45, 47; 297A.71, subdivision 8.
1.10 	BE IT ENACTED BY THE LEGISLATURE OF THE STATE OF MINNESOTA:

1.11 	Section 1. Minnesota Statutes 2018, section 216B.16, subdivision 6b, is amended to read:
1.12 		Subd. 6b.Energy conservation improvement. (a) Except as otherwise provided in this 
1.13 	subdivision, all investments and expenses of a public utility as defined in section 216B.241, 
1.14 	subdivision 1, paragraph (h), incurred in connection with energy conservation improvements 
1.15 	shall be recognized and included by the commission in the determination of just and 
1.16 	reasonable rates as if the investments and expenses were directly made or incurred by the 
1.17 	utility in furnishing utility service.
1.18 	(b) The commission shall not include investments and expenses for energy conservation 
1.19 	improvements in determining (i) just and reasonable electric rates for retail electric service 
1.20 	provided to large customer facilities whose electric utilities have been exempted by the 
1.21 	commissioner under section 216B.241, subdivision 1a, paragraph (b), with respect to those 
1.22 	large customer facilities; or (ii) just and reasonable gas rates for large energy facilities, large 
1.23 	customer facilities whose natural gas utilities have been exempted by the commissioner 
1.24 	under section 216B.241, subdivision 1a, paragraph (b), or commercial gas customer facilities 
2.1 	whose natural gas utilities have been exempted by the commissioner under section 216B.241, 
2.2 	subdivision 1a, paragraph (c).
2.3 	(c) The commission may permit a public utility to file rate schedules providing for annual 
2.4 	recovery of the costs of energy conservation improvements. These rate schedules may be 
2.5 	applicable to less than all the customers in a class of retail customers if necessary to reflect 
2.6 	the requirements of section 216B.241. The commission shall allow a public utility, without 
2.7 	requiring a general rate filing under this section, to reduce the electric rates applicable to 
2.8 	large customer facilities that have been exempted by the commissioner under section 
2.9 	216B.241, subdivision 1a, paragraph (b), and to reduce the gas rate applicable to a large 
2.10 	energy facility, a large customer facility or commercial customer facility that has been 
2.11 	exempted by the commissioner under section 216B.241, subdivision 1a, paragraph (b) or 
2.12 	(c), or by the commission under section 216B.241, subdivision 2, by an amount that reflects 
2.13 	the elimination of energy conservation improvement investments or expenditures for those 
2.14 	facilities. ~~In the event that the commission has set electric or gas rates based on the use of~~ 
2.15 	~~an accounting methodology that results in the cost of conservation improvements being~~ 
2.16 	~~recovered from utility customers over a period of years, the rate reduction may occur in a~~ 
2.17 	~~series of steps to coincide with the recovery of balances due to the utility for conservation~~ 
2.18 	~~improvements made by the utility on or before December 31, 2007.~~
2.19 	(d) Investments and expenses of a public utility shall not include electric utility 
2.20 	infrastructure costs as defined in section 216B.1636, subdivision 1, paragraph (b).

2.21 	Sec. 2. Minnesota Statutes 2018, section 216B.16, subdivision 19, is amended to read:
2.22 		Subd. 19.Multiyear rate plan. (a) A public utility may propose, and the commission 
2.23 	may approve, approve as modified, or reject, a multiyear rate plan as provided in this 
2.24 	subdivision. The term "multiyear rate plan" refers to a plan establishing the rates the utility 
2.25 	may charge for each year of the specified period of years, which cannot exceed five years, 
2.26 	to be covered by the plan. A utility proposing a multiyear rate plan shall provide a general 
2.27 	description of the utility's major planned investments over the plan period. The commission 
2.28 	may also require the utility to provide a set of reasonable performance measures and 
2.29 	incentives that are quantifiable, verifiable, and consistent with state energy policies. The 
2.30 	commission may allow the utility to adjust recovery of its cost of capital or other costs in 
2.31 	a reasonable manner within the plan period. The utility may propose:
2.32 	(1) recovery of the utility's forecasted rate base, based on a formula, a budget forecast, 
2.33 	or a fixed escalation rate, individually or in combination. The forecasted rate base must 
2.34 	include the utility's planned capital investments and investment-related costs, including 
3.1 	income tax impacts, depreciation, and property taxes, as well as forecasted capacity-related 
3.2 	costs from purchased power agreements that are not recovered through subdivision 7;
3.3 	(2) recovery of operations and maintenance expenses, based on an electricity-related 
3.4 	price index or other formula;
3.5 	(3) tariffs that expand the products and services available to customers, including, but 
3.6 	not limited to, an affordability rate for low-income residential customers; and
3.7 	(4) adjustments to the rates approved under the multiyear plan for rate changes that the 
3.8 	commission determines to be just and reasonable, including, but not limited to, changes in 
3.9 	the utility's cost of operating its nuclear facilities, or other significant investments not 
3.10 	addressed in the plan.
3.11 	(b) A utility that has filed a petition with the commission to approve a multiyear rate 
3.12 	plan may request to be allowed to implement interim rates for the first and second years of 
3.13 	the multiyear plan. If the commission approves the request, interim rates shall be implemented 
3.14 	in the same manner as allowed under subdivision 3.
3.15 	(c) The commission may approve a multiyear rate plan only if it finds that the plan 
3.16 	establishes just and reasonable rates for the utility, applying the factors described in 
3.17 	subdivision 6. Consistent with subdivision 4, the burden of proof to demonstrate that the 
3.18 	multiyear rate plan is just and reasonable is on the public utility proposing the plan.
3.19 	(d) Rates charged under the multiyear rate plan must be based only upon the utility's 
3.20 	reasonable and prudent costs of service over the term of the plan, as determined by the 
3.21 	commission, provided that the costs are not being recovered elsewhere in rates. Rate 
3.22 	adjustments authorized under subdivisions 6b and 7 may continue outside of a plan authorized 
3.23 	under this subdivision.
3.24 	(e) The commission may, by order, establish terms, conditions, and procedures for a 
3.25 	multiyear rate plan necessary to implement this section and ensure that rates remain just 
3.26 	and reasonable during the course of the plan, including terms and procedures for rate 
3.27 	adjustment. At any time prior to conclusion of a multiyear rate plan, the commission, upon 
3.28 	its own motion or upon petition of any party, has the discretion to examine the reasonableness 
3.29 	of the utility's rates under the plan, and adjust rates as necessary.
3.30 	(f) In reviewing a multiyear rate plan proposed in a general rate case under this section, 
3.31 	the commission may extend the time requirements for issuance of a final determination 
3.32 	prescribed in this section by an additional 90 days beyond its existing authority under 
3.33 	subdivision 2, paragraph (f).
4.1 	~~(g) A utility may not file a multiyear rate plan that would establish rates under the terms~~ 
4.2 	~~of the plan until after May 31, 2012.~~
4.3 	~~(h)~~ (g) The commission may initiate a proceeding to determine a set of performance 
4.4 	measures that can be used to assess a utility operating under a multiyear rate plan.

4.5 	Sec. 3. Minnesota Statutes 2018, section 216B.1645, subdivision 1, is amended to read:
4.6 		Subdivision 1.Commission authority. Upon the petition of a public utility, the Public 
4.7 	Utilities Commission shall approve or disapprove power purchase contracts, investments, 
4.8 	or expenditures entered into or made by the utility ~~to satisfy the wind and biomass mandates~~ 
4.9 	~~contained in sections 216B.169, 216B.2423, and 216B.2424, and~~ to satisfy the renewable 
4.10 	energy objectives and standards set forth in section 216B.1691, including reasonable 
4.11 	investments and expenditures made to:
4.12 	(1) transmit the electricity generated from sources developed under those sections that 
4.13 	is ultimately used to provide service to the utility's retail customers, including studies 
4.14 	necessary to identify new transmission facilities needed to transmit electricity to Minnesota 
4.15 	retail customers from generating facilities constructed to satisfy the renewable energy 
4.16 	objectives and standards, provided that the costs of the studies have not been recovered 
4.17 	previously under existing tariffs and the utility has filed an application for a certificate of 
4.18 	need or for certification as a priority project under section 216B.2425 for the new 
4.19 	transmission facilities identified in the studies;
4.20 	(2) provide storage facilities for renewable energy generation facilities that contribute 
4.21 	to the reliability, efficiency, or cost-effectiveness of the renewable facilities; or
4.22 	(3) develop renewable energy sources from the account required in section 116C.779.

4.23 	EFFECTIVE DATE. This section is effective the day following final enactment.

4.24 	Sec. 4. Minnesota Statutes 2018, section 216B.2422, subdivision 5, is amended to read:
4.25 		Subd. 5.Bidding; exemption from certificate of need proceeding. (a) A utility may 
4.26 	select resources to meet its projected energy demand through a bidding process approved 
4.27 	or established by the commission. A utility shall use the environmental cost estimates 
4.28 	determined under subdivision 3 in evaluating bids submitted in a process established under 
4.29 	this subdivision.
4.30 	(b) Notwithstanding any other provision of this section, if an electric power generating 
4.31 	plant, as described in section 216B.2421, subdivision 2, clause (1), is selected in a bidding 
5.1 	process approved or established by the commission, a certificate of need proceeding under 
5.2 	section 216B.243 is not required.
5.3 	~~(c) A certificate of need proceeding is also not required for an electric power generating~~ 
5.4 	~~plant that has been selected in a bidding process approved or established by the commission,~~ 
5.5 	~~or such other selection process approved by the commission, to satisfy, in whole or in part,~~ 
5.6 	~~the wind power mandate of section 216B.2423 or the biomass mandate of section 216B.2424.~~

5.7 	EFFECTIVE DATE. This section is effective the day following final enactment.

5.8 	Sec. 5. Minnesota Statutes 2018, section 272.0211, subdivision 1, is amended to read:
5.9 		Subdivision 1.Efficiency determination and certification. An owner or operator of a 
5.10 	new or existing electric power generation facility, excluding wind energy conversion systems, 
5.11 	may apply to the commissioner of revenue for a market value exclusion on the property as 
5.12 	provided for in this section. This exclusion shall apply only to the market value of the 
5.13 	equipment of the facility, and shall not apply to the structures and the land upon which the 
5.14 	facility is located. The commissioner of revenue shall prescribe the content, format, manner, 
5.15 	and procedures for this application pursuant to section 270C.30, except that a "law 
5.16 	administered by the commissioner" includes the property tax laws. If an application is made 
5.17 	by electronic means, the taxpayer's signature is defined pursuant to section 270C.304, except 
5.18 	that a "law administered by the commissioner" includes the property tax laws. Upon receiving 
5.19 	the application, the commissioner of revenue shall: (1) request the commissioner of commerce 
5.20 	to make a determination of the efficiency of the applicant's electric power generation facility; 
5.21 	and (2) shall develop an electronic means to notify interested parties when electric power 
5.22 	generation facilities have filed an application. The commissioner of commerce shall calculate 
5.23 	efficiency as the ratio of useful energy outputs to energy inputs, expressed as a percentage, 
5.24 	based on the performance of the facility's equipment during normal full load operation. The 
5.25 	commissioner must include in this formula the energy used in any on-site preparation of 
5.26 	materials necessary to convert the materials into the fuel used to generate electricity, such 
5.27 	as a process to gasify petroleum coke. The commissioner shall use the Higher Heating Value 
5.28 	(HHV) for all substances in the commissioner's efficiency calculations~~, except for wood~~ 
5.29 	~~for fuel in a biomass-eligible project under section 216B.2424; for these instances, the~~ 
5.30 	~~commissioner shall adjust the heating value to allow for energy consumed for evaporation~~ 
5.31 	~~of the moisture in the wood~~. The applicant shall provide the commissioner of commerce 
5.32 	with whatever information the commissioner deems necessary to make the determination. 
5.33 	Within 30 days of the receipt of the necessary information, the commissioner of commerce 
5.34 	shall certify the findings of the efficiency determination to the commissioner of revenue 
6.1 	and to the applicant. The commissioner of commerce shall determine the efficiency of the 
6.2 	facility and certify the findings of that determination to the commissioner of revenue every 
6.3 	two years thereafter from the date of the original certification.

6.4 	EFFECTIVE DATE. This section is effective the day following final enactment.

6.5 	Sec. 6. Minnesota Statutes 2018, section 282.04, subdivision 1, is amended to read:
6.6 		Subdivision 1.Timber sales; land leases and uses. (a) The county auditor, with terms 
6.7 	and conditions set by the county board, may sell timber upon any tract that may be approved 
6.8 	by the natural resources commissioner. The sale of timber shall be made for cash at not less 
6.9 	than the appraised value determined by the county board to the highest bidder after not less 
6.10 	than one week's published notice in an official paper within the county. Any timber offered 
6.11 	at the public sale and not sold may thereafter be sold at private sale by the county auditor 
6.12 	at not less than the appraised value thereof, until the time as the county board may withdraw 
6.13 	the timber from sale. The appraised value of the timber and the forestry practices to be 
6.14 	followed in the cutting of said timber shall be approved by the commissioner of natural 
6.15 	resources.
6.16 	(b) Payment of the full sale price of all timber sold on tax-forfeited lands shall be made 
6.17 	in cash at the time of the timber sale, except in the case of oral or sealed bid auction sales, 
6.18 	the down payment shall be no less than 15 percent of the appraised value, and the balance 
6.19 	shall be paid prior to entry. In the case of auction sales that are partitioned and sold as a 
6.20 	single sale with predetermined cutting blocks, the down payment shall be no less than 15 
6.21 	percent of the appraised price of the entire timber sale which may be held until the satisfactory 
6.22 	completion of the sale or applied in whole or in part to the final cutting block. The value of 
6.23 	each separate block must be paid in full before any cutting may begin in that block. With 
6.24 	the permission of the county contract administrator the purchaser may enter unpaid blocks 
6.25 	and cut necessary timber incidental to developing logging roads as may be needed to log 
6.26 	other blocks provided that no timber may be removed from an unpaid block until separately 
6.27 	scaled and paid for. If payment is provided as specified in this paragraph as security under 
6.28 	paragraph (a) and no cutting has taken place on the contract, the county auditor may credit 
6.29 	the security provided, less any down payment required for an auction sale under this 
6.30 	paragraph, to any other contract issued to the contract holder by the county under this chapter 
6.31 	to which the contract holder requests in writing that it be credited, provided the request and 
6.32 	transfer is made within the same calendar year as the security was received.
6.33 	(c) The county board may sell any timber, including biomass, as appraised or scaled. 
6.34 	Any parcels of land from which timber is to be sold by scale of cut products shall be so 
7.1 	designated in the published notice of sale under paragraph (a), in which case the notice shall 
7.2 	contain a description of the parcels, a statement of the estimated quantity of each species 
7.3 	of timber, and the appraised price of each species of timber for 1,000 feet, per cord or per 
7.4 	piece, as the case may be. In those cases any bids offered over and above the appraised 
7.5 	prices shall be by percentage, the percent bid to be added to the appraised price of each of 
7.6 	the different species of timber advertised on the land. The purchaser of timber from the 
7.7 	parcels shall pay in cash at the time of sale at the rate bid for all of the timber shown in the 
7.8 	notice of sale as estimated to be standing on the land, and in addition shall pay at the same 
7.9 	rate for any additional amounts which the final scale shows to have been cut or was available 
7.10 	for cutting on the land at the time of sale under the terms of the sale. Where the final scale 
7.11 	of cut products shows that less timber was cut or was available for cutting under terms of 
7.12 	the sale than was originally paid for, the excess payment shall be refunded from the forfeited 
7.13 	tax sale fund upon the claim of the purchaser, to be audited and allowed by the county board 
7.14 	as in case of other claims against the county. No timber, except hardwood pulpwood, may 
7.15 	be removed from the parcels of land or other designated landings until scaled by a person 
7.16 	or persons designated by the county board and approved by the commissioner of natural 
7.17 	resources. Landings other than the parcel of land from which timber is cut may be designated 
7.18 	for scaling by the county board by written agreement with the purchaser of the timber. The 
7.19 	county board may, by written agreement with the purchaser and with a consumer designated 
7.20 	by the purchaser when the timber is sold by the county auditor, and with the approval of 
7.21 	the commissioner of natural resources, accept the consumer's scale of cut products delivered 
7.22 	at the consumer's landing. No timber shall be removed until fully paid for in cash. Small 
7.23 	amounts of timber not exceeding 500 cords in appraised volume may be sold for not less 
7.24 	than the full appraised value at private sale to individual persons without first publishing 
7.25 	notice of sale or calling for bids, provided that in case of a sale involving a total appraised 
7.26 	value of more than $200 the sale shall be made subject to final settlement on the basis of a 
7.27 	scale of cut products in the manner above provided and not more than two of the sales, 
7.28 	directly or indirectly to any individual shall be in effect at one time.
7.29 	(d) As directed by the county board, the county auditor may lease tax-forfeited land to 
7.30 	individuals, corporations or organized subdivisions of the state at public or private sale, and 
7.31 	at the prices and under the terms as the county board may prescribe, for use as cottage and 
7.32 	camp sites and for agricultural purposes and for the purpose of taking and removing of hay, 
7.33 	stumpage, sand, gravel, clay, rock, marl, and black dirt from the land, and for garden sites 
7.34 	and other temporary uses provided that no leases shall be for a period to exceed ten years; 
7.35 	provided, further that any leases involving a consideration of more than $12,000 per year, 
7.36 	except to an organized subdivision of the state shall first be offered at public sale in the 
8.1 	manner provided herein for sale of timber. Upon the sale of any leased land, it shall remain 
8.2 	subject to the lease for not to exceed one year from the beginning of the term of the lease. 
8.3 	Any rent paid by the lessee for the portion of the term cut off by the cancellation shall be 
8.4 	refunded from the forfeited tax sale fund upon the claim of the lessee, to be audited and 
8.5 	allowed by the county board as in case of other claims against the county.
8.6 	(e) As directed by the county board, the county auditor may lease tax-forfeited land to 
8.7 	individuals, corporations, or organized subdivisions of the state at public or private sale, at 
8.8 	the prices and under the terms as the county board may prescribe, for the purpose of taking 
8.9 	and removing for use for road construction and other purposes tax-forfeited stockpiled 
8.10 	iron-bearing material. The county auditor must determine that the material is needed and 
8.11 	suitable for use in the construction or maintenance of a road, tailings basin, settling basin, 
8.12 	dike, dam, bank fill, or other works on public or private property, and that the use would 
8.13 	be in the best interests of the public. No lease shall exceed ten years. The use of a stockpile 
8.14 	for these purposes must first be approved by the commissioner of natural resources. The 
8.15 	request shall be deemed approved unless the requesting county is notified to the contrary 
8.16 	by the commissioner of natural resources within six months after receipt of a request for 
8.17 	approval for use of a stockpile. Once use of a stockpile has been approved, the county may 
8.18 	continue to lease it for these purposes until approval is withdrawn by the commissioner of 
8.19 	natural resources.
8.20 	(f) The county auditor, with the approval of the county board is authorized to grant 
8.21 	permits, licenses, and leases to tax-forfeited lands for the depositing of stripping, lean ores, 
8.22 	tailings, or waste products from mines or ore milling plants, or to use for facilities needed 
8.23 	to recover iron-bearing oxides from tailings basins or stockpiles, or for a buffer area needed 
8.24 	for a mining operation, upon the conditions and for the consideration and for the period of 
8.25 	time, not exceeding 25 years, as the county board may determine. The permits, licenses, or 
8.26 	leases are subject to approval by the commissioner of natural resources.
8.27 	(g) Any person who removes any timber from tax-forfeited land before said timber has 
8.28 	been scaled and fully paid for as provided in this subdivision is guilty of a misdemeanor.
8.29 	(h) The county auditor may, with the approval of the county board, and without first 
8.30 	offering at public sale, grant leases, for a term not exceeding 25 years, for the removal of 
8.31 	peat and for the production or removal of farm-grown closed-loop biomass as defined in 
8.32 	~~section 216B.2424,~~ subdivision ~~1~~ 1b, or short-rotation woody crops from tax-forfeited lands 
8.33 	upon the terms and conditions as the county board may prescribe. Any lease for the removal 
8.34 	of peat, farm-grown closed-loop biomass, or short-rotation woody crops from tax-forfeited 
8.35 	lands must first be reviewed and approved by the commissioner of natural resources if the 
9.1 	lease covers 320 or more acres. No lease for the removal of peat, farm-grown closed-loop 
9.2 	biomass, or short-rotation woody crops shall be made by the county auditor pursuant to this 
9.3 	section without first holding a public hearing on the auditor's intention to lease. One printed 
9.4 	notice in a legal newspaper in the county at least ten days before the hearing, and posted 
9.5 	notice in the courthouse at least 20 days before the hearing shall be given of the hearing.
9.6 	(i) Notwithstanding any provision of paragraph (c) to the contrary, the St. Louis County 
9.7 	auditor may, at the discretion of the county board, sell timber to the party who bids the 
9.8 	highest price for all the several kinds of timber, as provided for sales by the commissioner 
9.9 	of natural resources under section 90.14. Bids offered over and above the appraised price 
9.10 	need not be applied proportionately to the appraised price of each of the different species 
9.11 	of timber.
9.12 	(j) In lieu of any payment or deposit required in paragraph (b), as directed by the county 
9.13 	board and under terms set by the county board, the county auditor may accept an irrevocable 
9.14 	bank letter of credit in the amount equal to the amount otherwise determined in paragraph 
9.15 	(b). If an irrevocable bank letter of credit is provided under this paragraph, at the written 
9.16 	request of the purchaser, the county may periodically allow the bank letter of credit to be 
9.17 	reduced by an amount proportionate to the value of timber that has been harvested and for 
9.18 	which the county has received payment. The remaining amount of the bank letter of credit 
9.19 	after a reduction under this paragraph must not be less than 20 percent of the value of the 
9.20 	timber purchased. If an irrevocable bank letter of credit or cash deposit is provided for the 
9.21 	down payment required in paragraph (b), and no cutting of timber has taken place on the 
9.22 	contract for which a letter of credit has been provided, the county may allow the transfer 
9.23 	of the letter of credit to any other contract issued to the contract holder by the county under 
9.24 	this chapter to which the contract holder requests in writing that it be credited.

9.25 	EFFECTIVE DATE. This section is effective the day following final enactment.

9.26 	Sec. 7. Minnesota Statutes 2018, section 282.04, is amended by adding a subdivision to 
9.27 	read:
9.28 		Subd. 1b.Definitions. (a) For the purposes of this section, the following terms have the 
9.29 	meanings given them.
9.30 	(b) "Farm-grown closed-loop biomass" means herbaceous crops, trees, agricultural 
9.31 	waste, and aquatic plant matter that is used to generate electricity and that:
9.32 	(1) is intentionally cultivated, harvested, and prepared for use, in whole or in part, as a 
9.33 	fuel to generate electricity;
10.1 	(2) when combusted, releases an amount of carbon dioxide that is less than or 
10.2 	approximately equal to the carbon dioxide absorbed by the biomass fuel during its growing 
10.3 	cycle; and
10.4 	(3) is fired in a new or substantially retrofitted electric generating facility that is:
10.5 	(i) located within 400 miles of the biomass production site; and
10.6 	(ii) designed to use biomass to meet at least 75 percent of the electric generating facility's 
10.7 	fuel requirements.
10.8 	Farm-grown closed-loop biomass does not include mixed municipal solid waste, as defined 
10.9 	in section 115A.03.
10.10 	(c) "Sustainably managed woody biomass" means:
10.11 	(1) brush, trees, and other biomass harvested from within designated utility, railroad, 
10.12 	and road rights-of-way;
10.13 	(2) upland and lowland brush harvested from lands incorporated into Department of 
10.14 	Natural Resources brushland habitat management activities;
10.15 	(3) upland and lowland brush harvested from lands managed in accordance with the 
10.16 	Department of Natural Resources' "Best Management Practices for Managing Brushlands";
10.17 	(4) logging slash or waste wood that is (i) created by harvest, by precommercial timber 
10.18 	stand improvement to meet silvicultural objectives, or by fire, disease, or insect control 
10.19 	treatments, and (ii) managed in compliance with the Minnesota Forest Resources Council's 
10.20 	"Sustaining Minnesota Forest Resources: Voluntary Site-Level Forest Management 
10.21 	Guidelines for Landowners, Loggers and Resource Managers," as modified by this 
10.22 	subdivision; and
10.23 	(5) trees or parts of trees that, except as provided in clauses (1) to (3) and paragraph (a), 
10.24 	clause (1), do not meet the utilization standards for pulpwood, posts, bolts, or sawtimber as 
10.25 	described in (i) the Department of Natural Resources Division of Forestry Timber Sales 
10.26 	Manual, 1998, as amended as of May 1, 2005, and (ii) the Department of Natural Resources 
10.27 	Timber Scaling Manual, 1981, as amended as of May 1, 2005.

10.28 	Sec. 8. Minnesota Statutes 2018, section 282.04, is amended by adding a subdivision to 
10.29 	read:
10.30 		Subd. 1c.Eligible biomass fuel sources. The biomass fuel sources that meet the 
10.31 	requirements of subdivision 1b, paragraph (b), clauses (1) and (2), include but are not limited 
11.1 	to poplar, aspen, willow, switch grass, sorghum, alfalfa, cultivated prairie grass, and 
11.2 	sustainably managed woody biomass.

11.3 	Sec. 9. Minnesota Statutes 2018, section 282.04, is amended by adding a subdivision to 
11.4 	read:
11.5 		Subd. 1d.Legislative finding. The legislature finds that the negative environmental 
11.6 	impacts within 400 miles of the electric generating facility that are the result of transporting 
11.7 	and combusting biomass are offset in that region by the environmental benefits of the 
11.8 	biomass production to air, soil, and water.

11.9 	Sec. 10.  REPEALER.
 11.10 	Minnesota Statutes 2018, sections 116C.705; 116C.71, subdivisions 1a, 1b, 2c, and 3a; 
11.11 	116C.711; 116C.77; 116C.771; 116C.773; 216B.1611; 216B.1613; 216B.1646; 216B.1675, 
11.12 	subdivision 13; 216B.1681; 216B.1691, subdivisions 2 and 2d; 216B.1695; 216B.2423; 
11.13 	216B.2424; 216H.02, subdivisions 2, 3, 4, 5, and 6; 272.02, subdivisions 45 and 47; and 
11.14 	297A.71, subdivision 8, are repealed.

11.15 	EFFECTIVE DATE. This section is effective the day following final enactment.

APPENDIX 

Repealed Minnesota Statutes: 19-2716 

116C.705 FINDINGS.
The legislature finds that the disposal and transportation of high-level radioactive waste is of vital concern to the health, safety, and welfare of the people of Minnesota, and to the economic and environmental resources of Minnesota. To ensure the health, safety, and welfare of the people, and to protect the air, land, water, and other natural resources in the state from pollution, impairment, or destruction, it is necessary for the state to regulate and control, under the laws of the United States, the exploration for high-level radioactive waste disposal within the state of Minnesota. It is the intent of the legislature to exercise all legal authority for the purpose of regulating the disposal and transportation of high-level radioactive waste. 

116C.71 DEFINITIONS.Subd. 1a.Area characterization plan. 
"Area characterization plan" means the official plan prepared by the Department of Energy for a specific geographic area outlining the proposed laboratory or field activities to be undertaken to establish the geologic, environmental, social, and economic characteristics of the area. 

Subd. 1b.Area recommendation report. 
"Area recommendation report" means the official report prepared by the Department of Energy identifying specific geographic areas within a state for further evaluation as a repository for radioactive waste. 

Subd. 2c.Council. 
"Council" means the governor's Nuclear Waste Council. 

Subd. 3a.Potentially impacted area. 
"Potentially impacted area" means the area designated or described in a draft or final area recommendation report or area characterization plan for study or consideration. 

116C.711 NUCLEAR WASTE COUNCIL.Subdivision 1.Establishment. 
The governor's Nuclear Waste Council is established. 

Subd. 2.Membership. 
The council shall have at least nine members, consisting of: 

(1) the commissioners of health, transportation, and natural resources, and the commissioner of the Pollution Control Agency; 

(2) four citizen members appointed by the governor; 

(3) the director of the Minnesota Geological Survey; 

(4) one additional citizen from each potentially impacted area may be appointed by the governor if potentially impacted areas are designated in Minnesota; and 

(5) one Indian who is an enrolled member of a federally recognized Minnesota Indian tribe or band may be appointed by the governor if potentially impacted areas are designated in Minnesota and if those areas include Indian country as defined in United States Code, title 18, section 11.54. 

At least two members of the council must have expertise in the earth sciences. 

Subd. 3.Chair. 
A chair shall be appointed by the governor from the members of the council. 

Subd. 4.Advisory task force. 
The council may create advisory task forces under section 15.014, as are necessary to carry out its responsibilities under this chapter. 

Subd. 5.Membership regulation. 
Section 15.059 governs terms, compensation, removal, and filling of vacancies of members appointed by the governor. 

116C.77 LEGISLATIVE AUTHORIZATION FOR INDEPENDENT SPENT FUEL STORAGE INSTALLATION AT PRAIRIE ISLAND.
The legislature recognizes that: 

(1) the Minnesota Environmental Quality Board on May 16, 1991, reviewed and found adequate a final environmental impact statement ("EIS") on the proposal to construct and operate a dry cask storage facility for the temporary storage of spent nuclear fuel from the Prairie Island nuclear generating plant; 

(2) the United States Nuclear Regulatory Commission reviewed and approved a safety analysis report on the facility and on October 19, 1993, granted a license for the facility; and 

(3) the Public Utilities Commission in Docket No. E002/CN-91-91 reviewed the facility and approved a limited certificate of need approving the use of casks. 

The Minnesota legislature in compliance with section 116C.72, hereby ratifies and approves the EIS and the limited certificate of need and authorizes the use of casks at Prairie Island in accordance with the terms and conditions of the certificate of need as modified by Laws 1994, chapter 641, and without further environmental review under chapter 116D or further administrative review under section 216B.243. 

116C.771 ADDITIONAL CASK LIMITATIONS.
(a) Five casks may be filled and used at Prairie Island on May 11, 1994. 

(b) An additional four casks may be filled and used at Prairie Island if the Environmental Quality Board determines that, by December 31, 1996, the public utility operating the Prairie Island plant has filed a license application with the United States Nuclear Regulatory Commission for a spent nuclear fuel storage facility off of Prairie Island in Goodhue County, is continuing to make a good faith effort to implement the site, and has constructed, contracted for construction and operation, or purchased installed capacity of 100 megawatts of wind power in addition to wind power under construction or contract on May 11, 1994. 

(c)(1) An additional eight casks may be filled and placed at Prairie Island if the legislature has not revoked the authorization under clause (2) or the public utility has satisfied the wind power and biomass mandate requirements in sections 216B.2423, subdivision 1, paragraph (a), clause (1), and 216B.2424, subdivision 5, paragraph (a), clause (1), and the alternative site in Goodhue County is operational or under construction. 

(2) If the site is not under construction or operational or the wind mandates are not satisfied, the legislature may revoke the authorization for the additional eight casks by a law enacted prior to June 1, 1999. 

(d) Except as provided under paragraph (e), dry cask storage capacity for high-level nuclear waste within the state may not be increased beyond the casks authorized by section 116C.77 or their equivalent storage capacity. 

(e) This section does not prohibit a public utility from applying for or the Public Utilities Commission from granting a certificate of need for dry cask storage to accommodate the decommissioning of a nuclear power plant within this state. 

116C.773 CONTRACTUAL AGREEMENT.
The authorization for dry casks contained in section 116C.77 is not effective until the governor, on behalf of the state, and the public utility operating the Prairie Island nuclear plant enter into an agreement binding the parties to the terms of sections 116C.771 and 116C.772 and the mandate for 200 megawatts of wind power and 75 megawatts of biomass required by December 31, 2002, in sections 216B.2423, subdivision 1, and 216B.2424. The Mdewakanton Dakota Tribal Council at Prairie Island is an intended third-party beneficiary of this agreement and has standing to enforce the agreement. 

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. 3a.Project information. 
(a) Beginning July 1, 2014, each electric utility shall request an applicant for interconnection of distributed renewable energy generation to provide the following information, in a format prescribed by the commissioner: 

(1) the nameplate capacity of the facility in the application; 

(2) the preincentive installed cost and cost components of the generation system at the facility; 

(3) the energy source of the facility; and 

(4) the zip code in which the facility is to be located. 

(b) The commissioner shall develop or identify a system to collect and process the information under this subdivision for each utility, and make non-project-specific data available to the public on a periodic basis as determined by the commissioner, and in a format determined by the commissioner. The commissioner may solicit proposals from outside parties to develop the system. The commissioner may only collect data authorized in paragraph (a), and may not require submission of any additional data that could be used to personally identify any individual applicant or utility customer. 

(c) Electric utilities collecting and transferring data under this subdivision are not responsible for the accuracy, completeness, or quality of the information under this subdivision. 

(d) Except as provided in paragraph (b), any information provided by an applicant to the commissioner under this subdivision is nonpublic data as defined in section 13.02, subdivision 9. 

Subd. 4.Reporting requirements. 
(a) Each electric utility shall maintain records concerning applications received for interconnection and parallel operation of distributed generation. The records must include the date each application is received, documents generated in the course of processing each application, correspondence regarding each application, and the final disposition of each application. 

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

216B.1613 STANDARDIZED CONTRACT.
Within 60 days of May 20, 2009, each utility, as defined in section 216B.1691, subdivision 1, paragraph (b), shall file with the commission a standardized contract form for the purchase of electricity from projects with a nameplate capacity of five megawatts or less. The standardized contract form must be similar in all material respects to the standard contract form previously filed with the commission under section 216B.2423, subdivision 3, including any revisions to that contract on file with the commission as of May 20, 2009. After consultation with wind developers and producers, a utility governed by this section may modify the standardized contract currently on file under section 216B.2423 prior to submitting its standard contract form under this section if the modifications are reasonably necessary to account for circumstances that are unique to that particular utility. The commission shall not approve a contract that is not in compliance with this section. 

216B.1646 RATE REDUCTION; PROPERTY TAX REDUCTION.
(a) The commission shall, by any method the commission finds appropriate, reduce the rates each electric utility subject to rate regulation by the commission charges its customers to reflect, on an ongoing basis, the amount by which each utility's property tax on the personal property of its electric system from taxes payable in 2001 to taxes payable in 2002 is reduced. The commission must ensure that, to the extent feasible, each dollar of personal property tax reduction allocated to Minnesota consumers retroactive to January 1, 2002, results in a dollar of savings to the utility's customers. A utility may voluntarily pass on any additional property tax savings allocated in the same manner as approved by the commission under this paragraph. 

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

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

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

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

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

216B.1675 PERFORMANCE REGULATION PLAN FOR GAS UTILITY SERVICE.Subd. 13.General evaluation. 
The commission shall evaluate the effectiveness of all plans approved under this section and submit its findings to the legislature by January 1, 2012. 

216B.1681 CURTAILMENT PAYMENTS.
The commission shall conduct a study of curtailment payments for wind energy projects to assess whether utilities are unduly discriminating among project ownership structures in regard to the contractual availability of curtailment payments. The commission shall submit the study to the chairs and ranking minority members of the senate and house of representatives committees with primary jurisdiction over energy policy by January 15, 2008. 

216B.1691 RENEWABLE ENERGY OBJECTIVES.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. 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. 

216B.1695 ENVIRONMENTAL PROJECTS; ADVANCE DETERMINATION OF PRUDENCE.Subdivision 1.Qualifying project. 
A public utility may petition the commission for an advance determination of prudence for a project undertaken to comply with federal or state air quality standards of states in which the utility's electric generation facilities are located, if the project has an expected jurisdictional cost to Minnesota ratepayers of at least $10,000,000. A project is undertaken to comply with federal or state air quality standards if it is required: 

(1) by the state in which the generation facility is located in a state implementation plan, permit, or order; or 

(2) to comply with section 111 or 112 of the federal Clean Air Act, United States Code, title 42, section 7411 or 7412. 

Subd. 2.Regulatory cost assessments and reports. 
(a) A utility requesting an advance determination under subdivision 1 must, as part of the evidence required when filing a petition under subdivision 3, provide to the Public Utilities Commission and the Pollution Control Agency an assessment of all anticipated state and federal environmental regulations related to the production of electricity from the utility's facility subject to the filing, including regulations relating to: 

(1) air pollution by nitrogen oxide and sulphur dioxide, including an assumption that Minnesota will be included in the federal Clean Air Interstate Rule region, hazardous air pollutants, carbon dioxide, particulates, and ozone; 

(2) coal waste; and 

(3) water consumption and water pollution. 

(b) In addition, the utility shall provide an assessment of the financial and operational impacts of these pending regulations applicable to the generating facility that is the subject of the filing and provide a range of regulatory response scenarios that include, but are not limited to: 

(1) the installation of pollution control equipment; 

(2) the benefits of the retirement or repowering of the plant that is the subject of the filing with cleaner fuels considering the costs of complying with state and federal environmental regulations; and 

(3) the use of pollution allowances to achieve compliance. 

(c) The utility shall consult with interested stakeholders in establishing the scope of the regulatory, financial, and operational assessments prior to or during the 60-day period of the notice under subdivision 4. 

Subd. 3.Petition. 
A petition filed under this section must include a description of the project, evidence supporting the project's reasonableness, a discussion of project alternatives, a project implementation schedule, a cost estimate and support for the reasonableness of the estimated cost, and a description of the public utility's efforts to ensure the lowest reasonable costs. Following receipt of the Pollution Control Agency's verification under subdivision 4, the commission shall allow opportunity for oral and written comment on the petition. The commission shall make a final determination on the petition within ten months of its filing date. The commission must make findings in support of its determination. 

Subd. 4.Verification. 
At least 60 days prior to filing a petition to the commission under subdivision 3, the utility shall file notice with the Pollution Control Agency that describes the project and how it qualifies under subdivision 1. The Pollution Control Agency shall, within 60 days of receipt of the notice, verify that the project qualifies under subdivision 1, and shall forward written verification to the commission. 

Subd. 5.Cost recovery. 
The utility may begin recovery of costs that have been incurred by the utility in connection with implementation of the project in the next rate case following an advance determination of prudence or in a rider approved under section 216B.1692. The commission shall review the costs incurred by the utility for the project. The utility must show that the project costs are reasonable and necessary, and demonstrate its efforts to ensure the lowest reasonable project costs. Notwithstanding the commission's prior determination of prudence, it may accept, modify, or reject any of the project costs. The commission may determine whether to require an allowance for funds used during construction offset. 

Subd. 5a.Rate of return. 
The return on investment in the rider shall be at the level approved by the commission in the public utility's last general rate case, unless the commission determines that a different rate of return is in the public interest. 

Subd. 6.Expiration. 
A petition for an advance determination of prudence may not be filed after December 31, 2015. 

216B.2423 WIND POWER MANDATE.Subdivision 1.Mandate. 
A public utility, as defined in section 216B.02, subdivision 4, that operates a nuclear-powered electric generating plant within this state must construct and operate, purchase, or contract to construct and operate: (1) 225 megawatts of electric energy installed capacity generated by wind energy conversion systems within the state by December 31, 1998; and (2) an additional 200 megawatts of installed capacity so generated by December 31, 2002. 

For the purpose of this section, "wind energy conversion system" has the meaning given it in section 216C.06, subdivision 19. 

Subd. 2.Resource planning mandate. 
The Public Utilities Commission shall order a public utility subject to subdivision 1, to construct and operate, purchase, or contract to purchase an additional 400 megawatts of electric energy installed capacity generated by wind energy conversion systems by December 31, 2002, subject to resource planning and least cost planning requirements in section 216B.2422. 

Subd. 2a.Site preference. 
The Public Utilities Commission shall ensure that a utility subject to the requirements of subdivision 1, clause (2), shall implement that clause with a preference for wind energy conversion systems within the state. This preference shall not prevent the utility from constructing or contracting to construct wind energy conversion systems outside the state, if the Public Utilities Commission determines that selection of a facility within the state conflicts with the requirements of section 216B.03. 

Subd. 3.Standard contract for wind energy conversion systems. 
The Public Utilities Commission shall require a public utility subject to subdivision 1 to develop and file in a form acceptable to the commission by October 1, 1997, a standard form contract for the purchase of electricity from wind conversion systems with installed capacity of two megawatts and less. For purposes of applying the two megawatts limit, the installed capacity sold to the public utility from a single seller or affiliated group of sellers shall be cumulated. The standard contract shall include all the terms and conditions for purchasing wind-generated power by the utility, except for price and any other specific terms necessary to ensure system reliability and safety, which shall be separately negotiable. 

216B.2424 BIOMASS POWER MANDATE.Subdivision 1.Farm-grown closed-loop biomass. 
(a) For the purposes of this section, "farm-grown closed-loop biomass" means herbaceous crops, trees, agricultural waste, and aquatic plant matter that is used to generate electricity, but does not include mixed municipal solid waste, as defined in section 115A.03, and that: 

(1) is intentionally cultivated, harvested, and prepared for use, in whole or in part, as a fuel for the generation of electricity; 

(2) when combusted, releases an amount of carbon dioxide that is less than or approximately equal to the carbon dioxide absorbed by the biomass fuel during its growing cycle; and 

(3) is fired in a new or substantially retrofitted electric generating facility that is: 

(i) located within 400 miles of the site of the biomass production; and 

(ii) designed to use biomass to meet at least 75 percent of its fuel requirements. 

(b) The legislature finds that the negative environmental impacts within 400 miles of the facility resulting from transporting and combusting the biomass are offset in that region by the environmental benefits to air, soil, and water of the biomass production. 

(c) Among the biomass fuel sources that meet the requirements of paragraph (a), clauses (1) and (2), are poplar, aspen, willow, switch grass, sorghum, alfalfa, cultivated prairie grass, and sustainably managed woody biomass. 

(d) For the purpose of this section, "sustainably managed woody biomass" means: 

(1) brush, trees, and other biomass harvested from within designated utility, railroad, and road rights-of-way; 

(2) upland and lowland brush harvested from lands incorporated into brushland habitat management activities of the Minnesota Department of Natural Resources; 

(3) upland and lowland brush harvested from lands managed in accordance with Minnesota Department of Natural Resources "Best Management Practices for Managing Brushlands"; 

(4) logging slash or waste wood that is created by harvest, by precommercial timber stand improvement to meet silvicultural objectives, or by fire, disease, or insect control treatments, and that is managed in compliance with the Minnesota Forest Resources Council's "Sustaining Minnesota Forest Resources: Voluntary Site-Level Forest Management Guidelines for Landowners, Loggers and Resource Managers" as modified by the requirement of this subdivision; and 

(5) trees or parts of trees that do not meet the utilization standards for pulpwood, posts, bolts, or sawtimber as described in the Minnesota Department of Natural Resources Division of Forestry Timber Sales Manual, 1998, as amended as of May 1, 2005, and the Minnesota Department of Natural Resources Timber Scaling Manual, 1981, as amended as of May 1, 2005, except as provided in paragraph (a), clause (1), and this paragraph, clauses (1) to (3). 

Subd. 1a.Municipal waste-to-energy project. 
(a) This subdivision applies only to a biomass project owned or controlled, directly or indirectly, by two municipal utilities as described in subdivision 5a, paragraph (b). 

(b) Woody biomass from state-owned land must be harvested in compliance with an adopted management plan and a program of ecologically based third-party certification. 

(c) The project must prepare a fuel plan on an annual basis after commercial operation of the project as described in the power contract between the project and the public utility, and must also prepare annually certificates reflecting the types of fuel used in the preceding year by the project, as described in the power contract. The fuel plans and certificates shall also be filed with the Minnesota Department of Natural Resources and the Minnesota Department of Commerce within 30 days after being provided to the public utility, as provided by the power contract. Any person who believes the fuel plans, as amended, and certificates show that the project does not or will not comply with the fuel requirements of this subdivision may file a petition with the commission seeking such a determination. 

(d) The wood procurement process must utilize third-party audit certification systems to verify that applicable best management practices were utilized in the procurement of the sustainably managed biomass. If there is a failure to so verify in any two consecutive years during the original contract term, the farm-grown closed-loop biomass requirements of subdivision 2 must be increased to 50 percent for the remaining contract term period; however, if in two consecutive subsequent years after the increase has been implemented, it is verified that the conditions in this subdivision have been met, then for the remaining original contract term the closed-loop biomass mandate reverts to 25 percent. If there is a subsequent failure to verify in a year after the first failure and implementation of the 50 percent requirement, then the closed-loop percentage shall remain at 50 percent for each remaining year of the contract term. 

(e) In the closed-loop plantation, no transgenic plants may be used. 

(f) No wood may be harvested from any lands identified by the final or preliminary Minnesota County Biological Survey as having statewide significance as native plant communities, large populations or concentrations of rare species, or critical animal habitat. 

(g) A wood procurement plan must be prepared every five years and public meetings must be held and written comments taken on the plan and documentation must be provided on why or why not the public inputs were used. 

(h) Guidelines or best management practices for sustainably managed woody biomass must be adopted by: 

(1) the Minnesota Department of Natural Resources for managing and maintaining brushland and open land habitat on public and private lands, including, but not limited to, provisions of sections 84.941, 84.942, and 97A.125; and 

(2) the Minnesota Forest Resources Council for logging slash, using the most recent available scientific information regarding the removal of woody biomass from forest lands, to sustain the management of forest resources as defined by section 89.001, subdivisions 8 and 9, with particular attention to soil productivity, biological diversity as defined by section 89A.01, subdivision 3, and wildlife habitat. 

These guidelines must be completed by July 1, 2007, and the process of developing them must incorporate public notification and comment. 

(i) The University of Minnesota Initiative for Renewable Energy and the Environment is encouraged to solicit and fund high-quality research projects to develop and consolidate scientific information regarding the removal of woody biomass from forest and brush lands, with particular attention to the environmental impacts on soil productivity, biological diversity, and sequestration of carbon. The results of this research shall be made available to the public. 

(j) The two utilities owning or controlling, directly or indirectly, the biomass project described in subdivision 5a, paragraph (b), shall fund or obtain funding from nonstate sources of up to $150,000 by April 1, 2006, to complete the guidelines or best management practices described in paragraph (h). The expenditures to be funded under this paragraph do not include any of the expenditures to be funded under paragraph (i). 

Subd. 2.Interim exemption. 
(a) A biomass project proposing to use, as its primary fuel over the life of the project, short-rotation woody crops, may use as an interim fuel agricultural waste and other biomass which is not farm-grown closed-loop biomass for up to six years after the project's electric generating facility becomes operational; provided, the project developer demonstrates the project will use the designated short-rotation woody crops as its primary fuel after the interim period and provided the location of the interim fuel production meets the requirements of subdivision 1, paragraph (a), clause (3). 

(b) A biomass project proposing to use, as its primary fuel over the life of the project, short-rotation woody crops, may use as an interim fuel agricultural waste and other biomass which is not farm-grown closed-loop biomass for up to three years after the project's electric generating facility becomes operational; provided, the project developer demonstrates the project will use the designated short-rotation woody crops as its primary fuel after the interim period. 

(c) A biomass project that uses an interim fuel under the terms of paragraph (b) may, in addition, use an interim fuel under the terms of paragraph (a) for six years less the number of years that an interim fuel was used under paragraph (b). 

(d) A project developer proposing to use an exempt interim fuel under paragraphs (a) and (b) must demonstrate to the public utility that the project will have an adequate supply of short-rotation woody crops which meet the requirements of subdivision 1 to fuel the project after the interim period. 

(e) If a biomass project using an interim fuel under this subdivision is or becomes owned or controlled, directly or indirectly, by two municipal utilities as described in subdivision 5a, paragraph (b), the project is deemed to comply with the requirement under this subdivision to use as its primary fuel farm-grown closed-loop biomass if farm-grown closed-loop biomass comprises no less than 25 percent of the fuel used over the life of the project. For purposes of this subdivision, "life of the project" means 20 years from the date the project becomes operational or the term of the applicable power purchase agreement between the project owner and the public utility, whichever is longer. 

Subd. 3.Fuel exemption. 
Over the duration of the contract of a biomass power facility selected to satisfy the mandate in subdivision 5, fuel sources that are not biomass may be used to satisfy up to 25 percent of the fuel requirements of a biomass power facility selected to satisfy the biomass power mandate in subdivision 5, except that agricultural crop wastes, such as oat hulls, may be used to satisfy more than 25 percent of the fuel requirements of a power facility selected to satisfy the biomass power mandate in subdivision 5 if the wastes are co-fired with the fuel authorized for the facility. A biomass power facility selected to satisfy the mandate in subdivision 5 also may use fuel sources that are not biomass during any period when biomass fuel sources are not reasonably available to the facility due to any circumstances constituting an act of God. Fuel sources that are not biomass used during such a period of biomass fuel source unavailability shall not be counted toward the 25 percent exemption provided in this subdivision. For purposes of this subdivision, "act of God" means any natural disaster or other natural phenomenon of an exceptional, inevitable, or irresistible character, including, but not limited to, flood, fire, drought, earthquake, and crop failure resulting from climatic conditions, infestation, or disease. 

Subd. 4.Financial viability. 
A biomass project developer must demonstrate to the public utility evidence of sufficient financial viability necessary for the construction and operation of the biomass project. 

Subd. 5.Mandate. 
(a) A public utility, as defined in section 216B.02, subdivision 4, that operates a nuclear-powered electric generating plant within this state must construct and operate, purchase, or contract to construct and operate (1) by December 31, 1998, 50 megawatts of electric energy installed capacity generated by farm-grown closed-loop biomass scheduled to be operational by December 31, 2001; and (2) by December 31, 1998, an additional 75 megawatts of installed capacity so generated scheduled to be operational by December 31, 2002. 

(b) Of the 125 megawatts of biomass electricity installed capacity required under this subdivision, no more than 55 megawatts of this capacity may be provided by a facility that uses poultry litter as its primary fuel source and any such facility: 

(1) need not use biomass that complies with the definition in subdivision 1; 

(2) must enter into a contract with the public utility for such capacity, that has an average purchase price per megawatt hour over the life of the contract that is equal to or less than the average purchase price per megawatt hour over the life of the contract in contracts approved by the Public Utilities Commission before April 1, 2000, to satisfy the mandate of this section, and file that contract with the Public Utilities Commission prior to September 1, 2000; and 

(3) must schedule such capacity to be operational by December 31, 2002. 

(c) Of the total 125 megawatts of biomass electric energy installed capacity required under this section, no more than 75 megawatts may be provided by a single project. 

(d) Of the 75 megawatts of biomass electric energy installed capacity required under paragraph (a), clause (2), no more than 33 megawatts of this capacity may be provided by a St. Paul district heating and cooling system cogeneration facility utilizing waste wood as a primary fuel source. The St. Paul district heating and cooling system cogeneration facility need not use biomass that complies with the definition in subdivision 1. 

(e) The public utility must accept and consider on an equal basis with other biomass proposals: 

(1) a proposal to satisfy the requirements of this section that includes a project that exceeds the megawatt capacity requirements of either paragraph (a), clause (1) or (2), and that proposes to sell the excess capacity to the public utility or to other purchasers; and 

(2) a proposal for a new facility to satisfy more than ten but not more than 20 megawatts of the electrical generation requirements by a small business-sponsored independent power producer facility to be located within the northern quarter of the state, which means the area located north of Constitutional Route No. 8 as described in section 161.114, subdivision 2, and that utilizes biomass residue wood, sawdust, bark, chipped wood, or brush to generate electricity. A facility described in this clause is not required to utilize biomass complying with the definition in subdivision 1, but must be under construction by December 31, 2005. 

(f) If a public utility files a contract with the commission for electric energy installed capacity that uses poultry litter as its primary fuel source, the commission must do a preliminary review of the contract to determine if it meets the purchase price criteria provided in paragraph (b), clause (2). The commission shall perform its review and advise the parties of its determination within 30 days of filing of such a contract by a public utility. A public utility may submit by September 1, 2000, a revised contract to address the commission's preliminary determination. 

(g) The commission shall finally approve, modify, or disapprove no later than July 1, 2001, all contracts submitted by a public utility as of September 1, 2000, to meet the mandate set forth in this subdivision. 

(h) If a public utility subject to this section exercises an option to increase the generating capacity of a project in a contract approved by the commission prior to April 25, 2000, to satisfy the mandate in this subdivision, the public utility must notify the commission by September 1, 2000, that it has exercised the option and include in the notice the amount of additional megawatts to be generated under the option exercised. Any review by the commission of the project after exercise of such an option shall be based on the same criteria used to review the existing contract. 

(i) A facility specified in this subdivision qualifies for exemption from property taxation under section 272.02, subdivision 45. 

Subd. 5a.Reduction of biomass mandate. 
(a) Notwithstanding subdivision 5, the biomass electric energy mandate must be reduced from 125 megawatts to 110 megawatts. 

(b) The Public Utilities Commission shall approve a request pending before the commission as of May 15, 2003, for amendments to and assignment of a power purchase agreement with the owner of a facility that uses short-rotation, woody crops as its primary fuel previously approved to satisfy a portion of the biomass mandate if the owner of the project agrees to reduce the size of its project from 50 megawatts to 35 megawatts, while maintaining an average price for energy in nominal dollars measured over the term of the power purchase agreement at or below $104 per megawatt-hour, exclusive of any price adjustments that may take effect subsequent to commission approval of the power purchase agreement, as amended. The commission shall also approve, as necessary, any subsequent assignment or sale of the power purchase agreement or ownership of the project to an entity owned or controlled, directly or indirectly, by two municipal utilities located north of Constitutional Route No. 8, as described in section 161.114, which currently own electric and steam generation facilities using coal as a fuel and which propose to retrofit their existing municipal electrical generating facilities to utilize biomass fuels in order to perform the power purchase agreement. 

(c) If the power purchase agreement described in paragraph (b) is assigned to an entity that is, or becomes, owned or controlled, directly or indirectly, by two municipal entities as described in paragraph (b), and the power purchase agreement meets the price requirements of paragraph (b), the commission shall approve any amendments to the power purchase agreement necessary to reflect the changes in project location and ownership and any other amendments made necessary by those changes. The commission shall also specifically find that: 

(1) the power purchase agreement complies with and fully satisfies the provisions of this section to the full extent of its 35-megawatt capacity; 

(2) all costs incurred by the public utility and all amounts to be paid by the public utility to the project owner under the terms of the power purchase agreement are fully recoverable pursuant to section 216B.1645; 

(3) subject to prudency review by the commission, the public utility may recover from its Minnesota retail customers the amounts that may be incurred and paid by the public utility during the full term of the power purchase agreement; and 

(4) if the purchase power agreement meets the requirements of this subdivision, it is reasonable and in the public interest. 

(d) The commission shall specifically approve recovery by the public utility of any and all Minnesota jurisdictional costs incurred by the public utility to improve, construct, install, or upgrade transmission, distribution, or other electrical facilities owned by the public utility or other persons in order to permit interconnection of the retrofitted biomass-fueled generating facilities or to obtain transmission service for the energy provided by the facilities to the public utility pursuant to section 216B.1645, and shall disapprove any provision in the power purchase agreement that requires the developer or owner of the project to pay the jurisdictional costs or that permit the public utility to terminate the power purchase agreement as a result of the existence of those costs or the public utility's obligation to pay any or all of those costs. 

(e) Upon request by the project owner, the public utility shall agree to amend the power purchase agreement described in paragraph (b) and approved by the commission as required by paragraph (c). The amendment must be negotiated and executed within 45 days of May 14, 2013, and must apply to prices paid after January 1, 2014. The average price for energy in nominal dollars measured over the term of the power purchase agreement must not exceed $109.20 per megawatt hour. The public utility shall request approval of the amendment by the commission within 30 days of execution of the amended power purchase agreement. The amendment is not effective until approval by the commission. The commission shall act on the amendment within 90 days of submission of the request by the public utility. Upon approval of the amended power purchase agreement, the commission shall allow the public utility to recover the costs of the amended power purchase agreement, as provided in section 216B.1645. 

(f) With respect to the power purchase agreement described in paragraph (b), and amended and approved by the commission pursuant to paragraphs (c) and (e), upon request by the project owner, the public utility shall agree to amend the power purchase agreement to include a fuel cost adjustment clause which requires the public utility to reimburse the project owner monthly for all costs incurred by the project owner during the applicable month to procure and transport all fuel used to produce energy for delivery to the public utility pursuant to the power purchase agreement to the extent such costs exceeded $3.40 per million metric British thermal unit (MMBTU), in addition to the price to be paid for the energy produced and delivered by the project owner. Reimbursable costs include but are not limited to: (1) all costs incurred to load fuel at its source; (2) costs to transport fuel (i) to the biomass-fueled generating facilities or to an intermediate woodyard, storage facility, or handling facility, or (ii) from a facility to the biomass-fueled generating facilities; (3) depreciation of any depreciable loading, woodyard, storage, handling, or transportation equipment whether the vehicle or equipment is located at the fuel source, a woodyard, storage facility, handling facility, or at the generating facilities; and (4) costs to unload fuel at the generating facilities. Beginning with 2014, at the end of each calendar year of the term of the power purchase agreement, the project owner shall calculate the amount by which actual fuel costs for the year exceeded $3.40 per MMBTU, and prior monthly payment for such fuel costs shall be reconciled against actual fuel costs for the applicable calendar year. If such prior monthly fuel payments for the year in the aggregate exceed the amount due based on the annual calculation, the project owner shall credit the public utility for the excess paid. If the annual calculation of fuel costs due exceeds the prior monthly fuel payments for the year in the aggregate, the project owner shall be entitled to be paid for the deficiency with the next invoice to the public utility. The amendment shall be negotiated and executed within 45 days of May 13, 2013, and shall be effective for fuel costs incurred and prices after January 1, 2014. The public utility shall request approval of the amendment by the commission, and the commission shall approve the amendment as reasonable and in the public interest and allow the public utility to recover from its Minnesota retail customers the amounts paid by the public utility to the project owner pursuant to the power purchase agreement during the full term of the power purchase agreement, including the reimbursement of fuel costs pursuant to the power purchase agreement amendment, reimbursable costs as provided in this paragraph, pursuant to section 216B.1645, or otherwise. 

(g) With respect to the power purchase agreement described in paragraph (b) and approved by the commission pursuant to paragraphs (c) and (e), the public utility is prohibited from recovering from the project owner any costs which were not actually and reasonably incurred by the utility, notwithstanding any provision in the power purchase agreement to the contrary. In addition, beginning with 2012, the public utility shall pay for all energy delivered by the project owner pursuant to the power purchase agreement at the full price for such energy in the power purchase agreement approved and amended pursuant to paragraph (e), provided that the project owner does not deliver more than 110 percent of the amount scheduled for delivery in any year of the power purchase agreement, and does not deliver, on average over any five consecutive years of the power purchase agreement, an amount greater than 105 percent of the amount scheduled for delivery over the five-year period. 

Subd. 6.Remaining megawatt compliance process. 
(a) If there remain megawatts of biomass power generating capacity to fulfill the mandate in subdivision 5 after the commission has taken final action on all contracts filed by September 1, 2000, by a public utility, as amended and assigned, this subdivision governs final compliance with the biomass energy mandate in subdivision 5 subject to the requirements of subdivisions 7 and 8. 

(b) To the extent not inconsistent with this subdivision, the provisions of subdivisions 2, 3, 4, and 5 apply to proposals subject to this subdivision. 

(c) A public utility must submit proposals to the commission to complete the biomass mandate. The commission shall require a public utility subject to this section to issue a request for competitive proposals for projects for electric generation utilizing biomass as defined in paragraph (f) of this subdivision to provide the remaining megawatts of the mandate. The commission shall set an expedited schedule for submission of proposals to the utility, selection by the utility of proposals or projects, negotiation of contracts, and review by the commission of the contracts or projects submitted by the utility to the commission. 

(d) Notwithstanding the provisions of subdivisions 1 to 5 but subject to the provisions of subdivisions 7 and 8, a new or existing facility proposed under this subdivision that is fueled either by biomass or by co-firing biomass with nonbiomass may satisfy the mandate in this section. Such a facility need not use biomass that complies with the definition in subdivision 1 if it uses biomass as defined in paragraph (f) of this subdivision. Generating capacity produced by co-firing of biomass that is operational as of April 25, 2000, does not meet the requirements of the mandate, except that additional co-firing capacity added at an existing facility after April 25, 2000, may be used to satisfy this mandate. Only the number of megawatts of capacity at a facility which co-fires biomass that are directly attributable to the biomass and that become operational after April 25, 2000, count toward meeting the biomass mandate in this section. 

(e) Nothing in this subdivision precludes a facility proposed and approved under this subdivision from using fuel sources that are not biomass in compliance with subdivision 3. 

(f) Notwithstanding the provisions of subdivision 1, for proposals subject to this subdivision, "biomass" includes farm-grown closed-loop biomass; agricultural wastes, including animal, poultry, and plant wastes; and waste wood, including chipped wood, bark, brush, residue wood, and sawdust. 

(g) Nothing in this subdivision affects in any way contracts entered into as of April 25, 2000, to satisfy the mandate in subdivision 5. 

(h) Nothing in this subdivision requires a public utility to retrofit its own power plants for the purpose of co-firing biomass fuel, nor is a utility prohibited from retrofitting its own power plants for the purpose of co-firing biomass fuel to meet the requirements of this subdivision. 

Subd. 7.Effect on existing projects. 
The commission may not approve a project proposed after April 25, 2000, which would have an adverse impact on the ability of a project approved before April 25, 2000, to obtain an adequate supply of the fuel source designated for the project. 

Subd. 8.Agricultural biomass requirement. 
Of the 125 megawatts mandated in subdivision 5, or 110 megawatts mandated in subdivision 5a, at least 75 megawatts of the generating capacity must be generated by facilities that use agricultural biomass as the principal fuel source. For purposes of this subdivision, agricultural biomass includes only farm-grown closed-loop biomass and agricultural waste, including animal, poultry, and plant wastes. For purposes of this subdivision, "principal fuel source" means a fuel source that satisfies at least 75 percent of the fuel requirements of an electric power generating facility. Nothing in this subdivision is intended to expand the fuel source requirements of subdivision 5. 

Subd. 9.Adjustment of biomass fuel requirement. 
(a) Notwithstanding any provision in this section, the public utility subject to this section may, with respect to a facility approved under this section, file a petition with the commission for approval of: 

(1) a new or amended power purchase agreement; 

(2) the early termination of a power purchase agreement; or 

(3) the purchase and closure of the facility. 

(b) The commission may approve a new or amended power purchase agreement under this subdivision, notwithstanding the fuel requirements of this section, if the commission determines that: 

(1) all parties to the original power purchase agreement, or their successors or assigns, as applicable, agree to the terms and conditions of the new or amended power purchase agreement; and 

(2) the new or amended power purchase agreement is in the best interest of the customers of the public utility subject to this section, taking into consideration any savings realized by customers in the new or amended power purchase agreement and any costs imposed on customers under paragraph (e). A new or amended power purchase agreement approved under this paragraph may be for any term agreed to by the parties and may govern the purchase of any amount of energy. 

(c) The commission may approve the early termination of a power purchase agreement or the purchase and closure of a facility under this subdivision if it determines that: 

(1) all parties to the power purchase agreement, or their successors or assigns, as applicable, agree to the early termination of the power purchase agreement or the purchase and closure of the facility; and 

(2) the early termination of the power purchase agreement or the purchase and closure of the facility is in the best interest of the customers of the public utility subject to this section, taking into consideration any savings realized by customers as a result of the early termination of the power purchase agreement or the purchase and closure of the facility and any costs imposed on the customers under paragraph (e). 

(d) The commission's approval of a new or amended power purchase agreement under paragraph (b) or of the termination of a power purchase agreement or the purchase and closure of a facility under paragraph (c), shall not require the public utility subject to this section to purchase replacement amounts of biomass energy to fulfill the requirements of this section. 

(e) A utility may petition the commission to approve a rate schedule that provides for the automatic adjustment of charges to recover investments, expenses and costs, and earnings on the investments associated with a new or amended power purchase agreement, the early termination of a power purchase agreement, or the purchase and closure of a facility. The commission may approve the rate schedule upon a showing that the recovery of investments, expenses and costs, and earnings on the investments is less than the costs that would have been recovered from customers had the utility continued to purchase energy under the power purchase agreement in effect before any option available under this section is approved by the commission. If approved by the commission, cost recovery under this paragraph may include all cost recovery allowed for renewable facilities under section 216B.1645, subdivisions 2 and 2a. 

(f) This subdivision does not apply to a St. Paul district heating and cooling system cogeneration facility, and nothing in this subdivision precludes a public utility that operates a nuclear-power electric generating plant from filing a petition with the commission for approval of a new or amended power purchase agreement with such a facility. 

(g) For the purposes of this subdivision, "facility" means a biomass facility previously approved by the commission to satisfy a portion of the biomass mandate in this section. 

216H.02 GREENHOUSE GAS EMISSIONS CONTROL.Subd. 2.Climate change action plan. 
By February 1, 2008, the commissioner of commerce, in consultation with the commissioners of the Pollution Control Agency, the Housing Finance Agency, and the Departments of Natural Resources, Agriculture, Employment and Economic Development, and Transportation, and the chair of the Metropolitan Council, shall submit to the legislature a climate change action plan that meets the requirements of this section. 

Subd. 3.Stakeholder process. 
The plan required by subdivision 2 must be developed through a structured, broadly inclusive stakeholder-based review of potential policies and initiatives that will reduce statewide greenhouse gas emissions from a broad range of sources and activities. The commissioner shall engage a nationally recognized independent expert entity to conduct the stakeholder process. The report of the stakeholder process must form the basis for the plan submitted by the commissioner under subdivision 2. 

Subd. 4.General elements of the plan. 
The plan must: 

(1) estimate 1990 and 2005 greenhouse gas emissions in the state and make projections of emissions in 2015, 2025, and 2050; 

(2) identify, evaluate, and integrate a broad range of statewide greenhouse gas reduction options for all emission sectors in the state; 

(3) assess the costs, benefits, and feasibility of implementing the options; 

(4) recommend an integrated set of reduction options and strategies for implementing the options that will achieve the goals in subdivision 1, including analysis of the associated costs and benefits to Minnesotans; 

(5) estimate the statewide greenhouse gas emissions reductions anticipated from implementation of existing state policies; 

(6) recommend a system to require the reporting of statewide greenhouse gas emissions, identifying which facilities must report, and how emission estimates should be made; and 

(7) evaluate the option of exempting a project from the prohibitions contained in section 216H.03, subdivision 3, if the project contributes a specified fee per ton of carbon dioxide emissions emitted annually by the project, the proceeds of which would be used to fund permanent, quantifiable, verifiable, and enforceable reductions in greenhouse gas emissions that would not otherwise have occurred. 

Subd. 5.Specific plan requirements. 
(a) The plan must evaluate and recommend interim goals as steps to achieve the goals in subdivision 1. 

(b) The plan must determine the feasibility, assess the costs and benefits, and recommend how the state could adopt a regulatory system that imposes a cap on the aggregate air pollutant emissions of a group of sources, requires those subject to the cap to own an allowance for each ton of the air pollutant emitted, and allows for market-based trading of those allowances. The evaluation must contain an analysis of the state implementing a cap and trade system alone, in coordination with other states, and as a requirement of federal law applying to all states. The plan must recommend the parameters of a cap and trade system that includes a cap that would prevent significant increases in greenhouse gas emissions above current levels with a schedule for lowering the cap periodically to achieve the goals in subdivision 1 and interim goals recommended under paragraph (a). The plan must consider cost savings and cost increases on energy consumers in the state. 

(c) The plan must include recommendations for improvements in the emissions inventory and recommend whether the state should require greenhouse gas emissions reporting from specific sources and, if so, which sources should be required to report. The plan must also evaluate options for an emissions registry after reviewing registries in other states and recommend a registry that will insure the greatest opportunity for Minnesota entities to obtain marketable credits. 

Subd. 6.Regional activities. 
The state must, to the extent possible, with other states in the Midwest region, develop and implement a regional approach to reducing greenhouse gas emissions from activities in the region, including consulting on a regional cap and trade system. The commissioner of commerce shall coordinate Minnesota's regional activities under this subdivision and report to the legislative committees in the senate and house of representatives with jurisdiction over energy and environmental policy by February 1, 2008, and February 1, 2009, on the progress made and recommendations for further action. The commissioner of commerce, as part of the activities required under this subdivision, must meet with responsible officials from bordering states, other states in the Midwest region, and states in other regions of the country to: 

(1) determine whether other states are interested in establishing and cooperating in a multistate or regional greenhouse gas cap and trade allowance program; 

(2) identify and prepare an inventory of greenhouse gas reduction resources available to support a multistate or regional greenhouse gas cap and trade allowance program; 

(3) seek cooperation on a regional inventory of greenhouse gas emission sources; and 

(4) prepare an inventory of available renewable energy resources within a state or region. 

The commissioner of commerce must develop a definition of scope of this regional activity that is in addition to the components described in clauses (1) to (4). The commissioner must report on the additional scoping definitions to the chairs and ranking minority members of the legislative committees with jurisdiction over energy and environmental finance and policy on or before the commencement of the 2008 regular legislative session. 

272.02 EXEMPT PROPERTY.Subd. 45.Biomass electrical generation facility; personal property. 
Notwithstanding subdivision 9, clause (a), attached machinery and other personal property which is part of an electrical generating facility that meets the requirements of this subdivision is exempt. At the time of construction, the facility must: 

(1) be designed to utilize biomass as established in section 216B.2424 as a primary fuel source; and 

(2) be constructed for the purpose of generating power at the facility that will be sold pursuant to a contract approved by the Public Utilities Commission in accordance with the biomass mandate imposed under section 216B.2424. 

Construction of the facility must be commenced after January 1, 2000, and before December 31, 2005. Property eligible for this exemption does not include electric transmission lines and interconnections or gas pipelines and interconnections appurtenant to the property or facility. 

Subd. 47.Poultry litter biomass generation facility; personal property. 
Notwithstanding subdivision 9, clause (a), attached machinery and other personal property which is part of an electrical generating facility that meets the requirements of this subdivision is exempt. At the time of construction, the facility must: 

(1) be designed to utilize poultry litter as a primary fuel source; and 

(2) be constructed for the purpose of generating power at the facility that will be sold pursuant to a contract approved by the Public Utilities Commission in accordance with the biomass mandate imposed under section 216B.2424. 

Construction of the facility must be commenced after January 1, 2003, and before December 31, 2005. Property eligible for this exemption does not include electric transmission lines and interconnections or gas pipelines and interconnections appurtenant to the property or the facility. 

297A.71 CONSTRUCTION EXEMPTIONS.Subd. 8.Wood waste cogeneration facility. 
Building materials and supplies for constructing, equipping, or modifying a district heating and cooling system cogeneration facility are exempt if the facility: 

(1) utilizes wood waste as a primary fuel source; and 

(2) satisfies the requirements of the biomass mandate in section 216B.2424, subdivision 5.