STATE OF MICHIGAN

98TH LEGISLATURE

REGULAR SESSION OF 2016

Introduced by Senator Nofs

ENROLLED SENATE BILL No. 437

AN ACT to amend 1939 PA 3, entitled “An act to provide for the regulation and control of public and certain private utilities and other services affected with a public interest within this state; to provide for alternative energy suppliers; to provide for licensing; to include municipally owned utilities and other providers of energy under certain provisions of this act; to create a public service commission and to prescribe and define its powers and duties; to abolish the Michigan public utilities commission and to confer the powers and duties vested by law on the public service commission; to provide for the continuance, transfer, and completion of certain matters and proceedings; to abolish automatic adjustment clauses; to prohibit certain rate increases without notice and hearing; to qualify residential energy conservation programs permitted under state law for certain federal exemption; to create a fund; to provide for a restructuring of the manner in which energy is provided in this state; to encourage the utilization of resource recovery facilities; to prohibit certain acts and practices of providers of energy; to allow for the securitization of stranded costs; to reduce rates; to provide for appeals; to provide appropriations; to declare the effect and purpose of this act; to prescribe remedies and penalties; and to repeal acts and parts of acts,” by amending the title and sections 6a, 6j, 6k, 6l, 6m, 6s, 10, 10a, 10c, 10f, 10p, 10r, 10t, 10dd, and 11 (MCL 460.6a, 460.6j, 460.6k, 460.6l, 460.6m, 460.6s, 460.10, 460.10a, 460.10c, 460.10f, 460.10p, 460.10r, 460.10t, 460.10dd, and 460.11), the title as amended by 2005 PA 190, sections 6a, 10, 10a, 10p, and 10r as amended and sections 6s and 10dd as added by 2008 PA 286, section 6j as amended by 1987 PA 81, section 6k as added by 1982 PA 304, section 6l as amended and sections 10c, 10f, and 10t as added by 2000 PA 141, section 6m as amended by 2014 PA 170, and section 11 as amended by 2014 PA 169, and by adding sections 6t, 6u, 6v, 6w, 6x, 6z, 10ee, and 10ff; and to repeal acts and parts of acts.

The People of the State of Michigan enact:

TITLE

An act to provide for the regulation and control of public and certain private utilities and other services affected with a public interest within this state; to provide for alternative energy suppliers; to provide for licensing; to include municipally owned utilities and other providers of energy under certain provisions of this act; to create a public service commission and to prescribe and define its powers and duties; to abolish the Michigan public utilities commission and to confer the powers and duties vested by law on the public service commission; to provide for the powers and duties of certain state governmental officers and entities; to provide for the continuance, transfer, and completion of certain matters and proceedings; to abolish automatic adjustment clauses; to prohibit certain rate increases without notice and hearing; to qualify residential energy conservation programs permitted under state law for certain federal exemption; to create a fund; to encourage the utilization of resource recovery facilities; to prohibit certain acts and practices of providers of energy; to allow for the securitization of stranded costs; to reduce rates; to provide for appeals; to provide appropriations; to declare the effect and purpose of this act; to prescribe remedies and penalties; and to repeal acts and parts of acts.

Sec. 6a. (1) A gas utility, electric utility, or steam utility shall not increase its rates and charges or alter, change, or amend any rate or rate schedules, the effect of which will be to increase the cost of services to its customers, without first receiving commission approval as provided in this section. A utility shall coordinate with the commission staff in advance of filing its general rate case application under this section to avoid resource challenges with applications being filed at the same time as applications filed under this section by other utilities. In the case of electric utilities serving more than 1,000,000 customers in this state, the commission may, if necessary, order a delay in filing an application to establish a 21-day spacing between filings of electric utilities serving more than 1,000,000 customers in this state. The utility shall place in evidence facts relied upon to support the utility’s petition or application to increase its rates and charges, or to alter, change, or amend any rate or rate schedules. The commission shall require notice to be given to all interested parties within the service area to be affected, and all interested parties shall have a reasonable opportunity for a full and complete hearing. A utility may use projected costs and revenues for a future consecutive 12-month period in developing its requested rates and charges. The commission shall notify the utility within 30 days after filing, whether the utility’s petition or application is complete. A petition or application is considered complete if it complies with the rate application filing forms and instructions adopted under subsection (8). If the application is not complete, the commission shall notify the utility of all information necessary to make that filing complete. If the commission has not notified the utility within 30 days of whether the utility’s petition or application is complete, the application is considered complete. Concurrently with filing a complete application, or at any time after filing a complete application, a gas utility serving fewer than 1,000,000 customers in this state may file a motion seeking partial and immediate rate relief. After providing notice to the interested parties within the service area to be affected and affording interested parties a reasonable opportunity to present written evidence and written arguments relevant to the motion seeking partial and immediate rate relief, the commission shall make a finding and enter an order granting or denying partial and immediate relief within 180 days after the motion seeking partial and immediate rate relief was submitted. The commission has 12 months to issue a final order in a case in which a gas utility has filed a motion seeking partial and immediate rate relief.

(2) If the commission has not issued an order within 180 days of the filing of a complete application, the utility may implement up to the amount of the proposed annual rate request through equal percentage increases or decreases applied to all base rates. If the utility uses projected costs and revenues for a future period in developing its requested rates and charges, the utility may not implement the equal percentage increases or decreases before the calendar date corresponding to the start of the projected 12-month period. For good cause, the commission may issue a temporary order preventing or delaying a utility from implementing its proposed rates or charges. If a utility implements increased rates or charges under this subsection before the commission issues a final order, that utility shall refund to customers, with interest, any portion of the total revenues collected through application of the equal percentage increase that exceed the total that would have been produced by the rates or charges subsequently ordered by the commission in its final order. The commission shall allocate any refund required by this subsection among primary customers based upon their pro rata share of the total revenue collected through the applicable increase, and among secondary and residential customers in a manner to be determined by the commission. The rate of interest for refunds shall equal 5% plus the London interbank offered rate (LIBOR) for the appropriate time period. For any portion of the refund that, exclusive of interest, exceeds 25% of the annual revenue increase awarded by the commission in its final order, the rate of interest shall be the authorized rate of return on the common stock of the utility during the appropriate period. Any refund or interest awarded under this subsection shall not be included, in whole or in part, in any application for a rate increase by a utility. This subsection only applies to completed applications filed with the commission before the effective date of the amendatory act that added section 6t.

(3) This section does not impair the commission’s ability to issue a show cause order as part of its rate-making authority. An alteration or amendment in rates or rate schedules applied for by a public utility that will not result in an increase in the cost of service to its customers may be authorized and approved without notice or hearing. There shall be no increase in rates based upon changes in cost of fuel, purchased gas, or purchased steam unless notice has been given within the service area to be affected, and there has been an opportunity for a full and complete hearing on the cost of fuel, purchased gas, or purchased steam. The rates charged by any utility under an automatic fuel, purchased gas, or purchased steam adjustment clause shall not be altered, changed, or amended unless notice has been given within the service area to be affected, and there has been an opportunity for a full and complete hearing on the cost of the fuel, purchased gas, or purchased steam.

(4) The commission shall adopt rules and procedures for the filing, investigation, and hearing of petitions or applications to increase or decrease utility rates and charges as the commission finds necessary or appropriate to enable it to reach a final decision with respect to petitions or applications within a period of time allotted by law to issue a final order after the filing of the complete petitions or applications. The commission shall not authorize or approve adjustment clauses that operate without notice and an opportunity for a full and complete hearing, and all such clauses are abolished. The commission may hold a full and complete hearing to determine the cost of fuel, purchased gas, purchased steam, or purchased power separately from a full and complete hearing on a general rate case and may hold that hearing concurrently with the general rate case. The commission shall authorize a utility to recover the cost of fuel, purchased gas, purchased steam, or purchased power only to the extent that the purchases are reasonable and prudent.

(5) Except as otherwise provided in this subsection and subsection (1), if the commission fails to reach a final decision with respect to a completed petition or application to increase or decrease utility rates within the 10-month period following the filing of the completed petition or application, the petition or application is considered approved. If a utility makes any significant amendment to its filing, the commission has an additional 10 months after the date of the amendment to reach a final decision on the petition or application. If the utility files for an extension of time, the commission shall extend the 10-month period by the amount of additional time requested by the utility.

(6) A utility shall not file a general rate case application for an increase in rates earlier than 12 months after the date of the filing of a complete prior general rate case application. A utility may not file a new general rate case application until the commission has issued a final order on a prior general rate case or until the rates are approved under subsection (5).

(7) The commission shall, if requested by a gas utility, establish load retention transportation rate schedules or approve gas transportation contracts as required for the purpose of serving industrial or commercial customers whose individual annual transportation volumes exceed 500,000 decatherms on the gas utility’s system. The commission shall approve these rate schedules or approve transportation contracts entered into by the utility in good faith if the industrial or commercial customer has the installed capability to use an alternative fuel or otherwise has a viable alternative to receiving natural gas transportation service from the utility, the customer can obtain the alternative fuel or gas transportation from an alternative source at a price that would cause them not to use the gas utility’s system, and the customer, as a result of their use of the system and receipt of transportation service, makes a significant contribution to the utility’s fixed costs. The commission shall adopt accounting and rate-making policies to ensure that the discounts associated with the transportation rate schedules and contracts are recovered by the gas utility through charges applicable to other customers if the incremental costs related to the discounts are no greater than the costs that would be passed on to those customers as the result of a loss of the industrial or commercial customer’s contribution to a utility’s fixed costs.

(8) The commission shall adopt standard rate application filing forms and instructions for use in all general rate cases filed by utilities whose rates are regulated by the commission. For cooperative electric utilities whose rates are regulated by the commission, in addition to rate applications filed under this section, the commission shall continue to allow for rate filings based on the cooperative’s times interest earned ratio. The commission may modify the standard rate application forms and instructions adopted under this subsection.

(9) If, on or before January 1, 2008, a merchant plant entered into a contract with an initial term of 20 years or more to sell electricity to an electric utility whose rates are regulated by the commission with 1,000,000 or more retail customers in this state and if, before January 1, 2008, the merchant plant generated electricity under that contract, in whole or in part, from wood or solid wood wastes, then the merchant plant shall, upon petition by the merchant plant, and subject to the limitation set forth in subsection (10), recover the amount, if any, by which the merchant plant’s reasonably and prudently incurred actual fuel and variable operation and maintenance costs exceed the amount that the merchant plant is paid under the contract for those costs. This subsection does not apply to landfill gas plants, hydro plants, municipal solid waste plants, or to merchant plants engaged in litigation against an electric utility seeking higher payments for power delivered pursuant to contract.

(10) The total aggregate additional amounts recoverable by merchant plants under subsection (9) in excess of the amounts paid under the contracts shall not exceed $1,000,000.00 per month for each affected electric utility. The $1,000,000.00 per month limit specified in this subsection shall be reviewed by the commission upon petition of the merchant plant filed no more than once per year and may be adjusted if the commission finds that the eligible merchant plants reasonably and prudently incurred actual fuel and variable operation and maintenance costs exceed the amount that those merchant plants are paid under the contract by more than $1,000,000.00 per month. The annual amount of the adjustments shall not exceed a rate equal to the United States consumer price index. The commission shall not make an adjustment unless each affected merchant plant files a petition with the commission. If the total aggregate amount by which the eligible merchant plants reasonably and prudently incurred actual fuel and variable operation and maintenance costs determined by the commission exceed the amount that the merchant plants are paid under the contract by more than $1,000,000.00 per month, the commission shall allocate the additional $1,000,000.00 per month payment among the eligible merchant plants based upon the relationship of excess costs among the eligible merchant plants. The $1,000,000.00 limit specified in this subsection, as adjusted, does not apply to actual fuel and variable operation and maintenance costs that are incurred due to changes in federal or state environmental laws or regulations that are implemented after October 6, 2008. The $1,000,000.00 per month payment limit under this subsection does not apply to merchant plants eligible under subsection (9) whose electricity is purchased by a utility that is using wood or wood waste or fuels derived from those materials for fuel in their power plants. As used in this subsection, “United States consumer price index” means the United States consumer price index for all urban consumers as defined and reported by the United States Department of Labor, Bureau of Labor Statistics.

(11) The commission shall issue orders to permit the recovery authorized under subsections (9) and (10) upon petition of the merchant plant. The merchant plant is not required to alter or amend the existing contract with the electric utility in order to obtain the recovery under subsections (9) and (10). The commission shall permit or require the electric utility whose rates are regulated by the commission to recover from its ratepayers all fuel and variable operation and maintenance costs that the electric utility is required to pay to the merchant plant as reasonably and prudently incurred costs.

(12) Subject to subsection (13), if requested by an electric utility with less than 200,000 customers in this state, the commission shall approve an appropriate revenue decoupling mechanism that adjusts for decreases in actual sales compared to the projected levels used in that utility’s most recent rate case that are the result of implemented energy waste reduction, conservation, demand-side programs, and other waste reduction measures, if the utility first demonstrates the following to the commission:

(a) That the projected sales forecast in the utility’s most recent rate case is reasonable.

(b) That the electric utility has achieved annual incremental energy savings at least equal to the lesser of the following:

(i) One percent of its total annual retail electricity sales in the previous year.

(ii) The amount of any incremental savings yielded by energy waste reduction, conservation, demand-side programs, and other waste reduction measures approved by the commission in that utility’s most recent integrated resource plan.

(13) The commission shall consider the aggregate revenues attributable to revenue decoupling mechanisms, financial incentives, and shared savings mechanisms the commission has approved for an electric utility relative to energy waste reduction, conservation, demand-side programs, peak load reduction, and other waste reduction measures. The commission may approve an alternative methodology for a revenue decoupling mechanism authorized under subsection (12), a financial incentive authorized under section 75 of the clean and renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1075, or a shared savings mechanism authorized under section 6x if the commission determines that the resulting aggregate revenues from those mechanisms would not result in a reasonable and cost‑effective method to ensure that investments in energy waste reduction, demand-side programs, peak load reduction, and other waste reduction measures are not disfavored when compared to utility supply-side investments. The commission’s consideration of an alternative methodology under this subsection shall be conducted as a contested case pursuant to chapter 4 of the administrative procedures act of 1969, 1969 PA 306, MCL 24.271 to 24.287.

(14) Within 1 year after the effective date of the amendatory act that added this subsection, the commission shall conduct a study on an appropriate tariff reflecting equitable cost of service for utility revenue requirements for customers who participate in a net metering program or distributed generation program under the clean and renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1001 to 460.1211. In any rate case filed after June 1, 2018, the commission shall approve such a tariff for inclusion in the rates of all customers participating in a net metering or distributed generation program under the clean and renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1001 to 460.1211. A tariff established under this subsection does not apply to customers participating in a net metering program under the clean and renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1001 to 460.1211, before the date that the commission establishes a tariff under this subsection, who continues to participate in the program at their current site or facility.

(15) Except as otherwise provided in this act, “utility” and “electric utility” do not include a municipally owned electric utility.

(16) As used in this section:

(a) “Full and complete hearing” means a hearing that provides interested parties a reasonable opportunity to present and cross-examine evidence and present arguments relevant to the specific element or elements of the request that are the subject of the hearing.

(b) “General rate case” means a proceeding initiated by a utility in an application filed with the commission that alleges a revenue deficiency and requests an increase in the schedule of rates or charges based on the utility’s total cost of providing service.

(c) “Steam utility” means a steam distribution company regulated by the commission.

Sec. 6j. (1) As used in this act:

(a) “Long-term firm gas transportation” means a binding agreement entered into between the electric utility and a natural gas transmission provider for a set period of time to provide firm delivery of natural gas to an electric generation facility.

(b) “Power supply cost recovery clause” means a clause in the electric rates or rate schedule of an electric utility that permits the monthly adjustment of rates for power supply to allow the utility to recover the booked costs, including transportation costs, reclamation costs, and disposal and reprocessing costs, of fuel burned by the utility for electric generation and the booked costs of purchased and net interchanged power transactions by the utility incurred under reasonable and prudent policies and practices.

(c) “Power supply cost recovery factor” means that element of the rates to be charged for electric service to reflect power supply costs incurred by an electric utility and made pursuant to a power supply cost recovery clause incorporated in the rates or rate schedule of an electric utility.

(2) The public service commission may incorporate a power supply cost recovery clause in the electric rates or rate schedule of an electric utility. Any order incorporating a power supply cost recovery clause shall be as a result of a hearing solely on the question of the inclusion of the clause in the rates or rate schedule. A hearing under this subsection shall be conducted as a contested case pursuant to chapter 4 of the administrative procedures act of 1969, 1969 PA 306, MCL 24.271 to 24.287, or, pursuant to subsection (18), as a result of a general rate case. Any order incorporating a power supply cost recovery clause shall replace and rescind any previous fuel cost adjustment clause or purchased and net interchanged power adjustment clause incorporated in the electric rates of the utility upon the effective date of the first power supply cost recovery factor authorized for the utility under its power supply cost recovery clause.

(3) In order to implement the power supply cost recovery clause established under subsection (2), an electric utility annually shall file, pursuant to procedures established by the commission, if any, a complete power supply cost recovery plan describing the expected sources of electric power supply and changes in the cost of power supply anticipated over a future 12-month period specified by the commission and requesting for each of those 12 months a specific power supply cost recovery factor. The utility shall file the plan not later than 3 months before the beginning of the 12-month period covered by the plan. The plan shall describe all major contracts and power supply arrangements entered into by the utility for providing power supply during the specified 12-month period. The description of the major contracts and arrangements shall include the price of fuel, the duration of the contract or arrangement, and an explanation or description of any other term or provision as required by the commission. For gas fuel supply contracts or arrangements, the description shall include whether the supply contracts or arrangements include long-term firm gas transportation and, if not, an explanation of how the utility proposes to ensure reliable and reasonably priced gas fuel supply to its generation facilities during the specified 12-month period. The plan shall also include the utility’s evaluation of the reasonableness and prudence of its decisions to provide power supply in the manner described in the plan, in light of its existing sources of electrical generation, and an explanation of the actions taken by the utility to minimize the cost of fuel to the utility.

(4) In order to implement the power supply cost recovery clause established under subsection (2), a utility shall file, contemporaneously with the power supply cost recovery plan required by subsection (3), a 5-year forecast of the power supply requirements of its customers, its anticipated sources of supply, and projections of power supply costs, in light of its existing sources of electrical generation and sources of electrical generation under construction. The forecast shall include a description of all relevant major contracts and power supply arrangements entered into or contemplated by the utility, and any other information the commission may require.

(5) If an electric utility files a power supply cost recovery plan under subsection (3) and a 5-year forecast under subsection (4), the commission shall conduct a proceeding, to be known as a power supply and cost review, for the purpose of evaluating the reasonableness and prudence of the power supply cost recovery plan filed by a utility under subsection (3), and establishing the power supply cost recovery factors to implement a power supply cost recovery clause incorporated in the electric rates or rate schedule of the utility. The power supply and cost review shall be conducted as a contested case pursuant to chapter 4 of the administrative procedures act of 1969, 1969 PA 306, MCL 24.271 to 24.287.

(6) In its final order in a power supply and cost review, the commission shall evaluate the reasonableness and prudence of the decisions underlying the power supply cost recovery plan filed by an electric utility under subsection (3), and shall approve, disapprove, or amend the power supply cost recovery plan accordingly. In evaluating the decisions underlying the power supply cost recovery plan, the commission shall consider the cost and availability of the electrical generation available to the utility; the cost of short-term firm purchases available to the utility; the availability of interruptible service; the ability of the utility to reduce or to eliminate any firm sales to out-of-state customers if the utility is not a multi-state utility whose firm sales are subject to other regulatory authority; whether the utility has taken all appropriate actions to minimize the cost of fuel; and other relevant factors. The commission shall approve, reject, or amend the 12 monthly power supply cost recovery factors requested by the utility in its power supply cost recovery plan. The factors shall not reflect items the commission could reasonably anticipate would be disallowed under subsection (13). The factors ordered shall be described in fixed dollar amounts per unit of electricity, but may include specific amounts contingent on future events.

(7) In its final order in a power supply and cost review, the commission shall evaluate the decisions underlying the 5-year forecast filed by a utility under subsection (4). The commission may also indicate any cost items in the 5-year forecast that, on the basis of present evidence, the commission would be unlikely to permit the utility to recover from its customers in rates, rate schedules, or power supply cost recovery factors established in the future.

(8) The commission, on its own motion or the motion of any party, may make a finding and enter a temporary order granting approval or partial approval of a power supply cost recovery plan in a power supply and cost recovery review, after first giving notice to the parties to the review, and after giving the parties to the review a reasonable opportunity for a full and complete hearing. A temporary order made under this subsection is considered a final order for purposes of judicial review.

(9) If the commission has made a final or temporary order in a power supply and cost review, an electric utility may each month incorporate in its rates for the period covered by the order any amounts up to the power supply cost recovery factors permitted in that order. If the commission has not made a final or temporary order within 3 months after the submission of a complete power supply cost recovery plan, or by the beginning of the period covered in the plan, whichever comes later, or if a temporary order has expired without being extended or replaced, then pending an order that determines the power supply cost recovery factors, a utility may each month adjust its rates to incorporate all or a part of the power supply cost recovery factors requested in its plan. Any amounts collected under the power supply cost recovery factors before the commission makes its final order is subject to prompt refund with interest to the extent that the total amounts collected exceed the total amounts determined in the commission’s final order to be reasonable and prudent for the same period of time.

(10) Not later than 3 months before the beginning of the third quarter of the 12-month period described in subsection (3), an electric utility may file a revised power supply cost recovery plan that covers the remainder of the 12-month period. Upon receipt of the revised power supply cost recovery plan, the commission shall reopen the power supply and cost review. In addition, the commission may reopen the power supply and cost review on its own motion or on the showing of good cause by any party if at least 6 months have elapsed since the utility submitted its complete filing and if there are at least 60 days remaining in the 12-month period under consideration. A reopened power supply and cost review shall be conducted as a contested case pursuant to chapter 4 of the administrative procedures act of 1969, 1969 PA 306, MCL 24.271 to 24.287, and in accordance with subsections (3), (6), (8), and (9).

(11) Not later than 45 days after the last day of each billing month in which a power supply cost recovery factor has been applied to customers’ bills, an electric utility shall file with the commission a detailed statement for that month of the revenues recorded pursuant to the power supply cost recovery factor and the allowance for cost of power supply included in the base rates established in the latest commission order for the utility, and the cost of power supply. The detailed statement shall be in the manner and form prescribed by the commission. The commission shall establish procedures for insuring that the detailed statement is promptly verified and corrected if necessary.

(12) Not less than once a year, and not later than 3 months after the end of the 12-month period covered by an electric utility’s power supply cost recovery plan, the commission shall commence a proceeding, to be known as a power supply cost reconciliation, as a contested case pursuant to chapter 4 of the administrative procedures act of 1969, 1969 PA 306, MCL 24.271 to 24.287. The commission shall permit reasonable discovery before and during the reconciliation proceeding in order to assist parties and interested persons in obtaining evidence concerning reconciliation issues including, but not limited to, the reasonableness and prudence of expenditures and the amounts collected pursuant to the clause. At the power supply cost reconciliation the commission shall reconcile the revenues recorded pursuant to the power supply cost recovery factors and the allowance for cost of power supply included in the base rates established in the latest commission order for the utility with the amounts actually expensed and included in the cost of power supply by the utility. The commission shall consider any issue regarding the reasonableness and prudence of expenses for which customers were charged if the issue was not considered adequately at a previously conducted power supply and cost review.

(13) In its order in a power supply cost reconciliation, the commission shall do all of the following:

(a) Disallow cost increases resulting from changes in accounting or rate-making expense treatment not previously approved by the commission. The commission may order the utility to pay a penalty of not more than 25% of the amount improperly collected. Costs incurred by the utility for penalty payments shall not be charged to customers.

(b) Not disallow the capacity charges for any facilities for which the electric utility would otherwise have a purchase obligation if the commission has approved capacity charges in a contract with a qualifying facility, as that term is defined by the Federal Energy Regulatory Commission pursuant to the public utilities regulatory policies act of 1978, Public Law 95-617, 92 Stat 3117, unless the commission has ordered revised capacity charges upon reconsideration under this subsection. A contract is valid and binding in accordance with its terms, and capacity charges paid pursuant to that contract are recoverable costs of the utility for rate-making purposes notwithstanding that the order approving that contract is later vacated, modified, or otherwise held to be invalid in whole or in part if the order approving the contract has not been stayed or suspended by a competent court within 30 days after the date of the order, or by July 29, 1987 if the order was issued after September 1, 1986 and before June 29, 1987. The commission shall determine the scope and manner of the review of capacity charges for a qualifying facility. Except as to approvals for qualifying facilities granted by the commission before June 1, 1987, proceedings before the commission seeking those approvals shall be conducted as a contested case pursuant to chapter 4 of the administrative procedures act of 1969, 1969 PA 306, MCL 24.271 to 24.287. The commission, upon its own motion or upon application of any person, may reconsider its approval of capacity charges for a qualifying facility in a contested case hearing after passage of a period necessary for financing the qualifying facility, if both of the following apply:

(i) The commission has first issued an order making a finding based on evidence presented in a contested case that there has been a substantial change in circumstances since the commission’s initial approval.

(ii) The commission finding is set forth in a commission order subject to immediate judicial review.

The financing period for a qualifying facility during which previously approved capacity charges are not subject to commission reconsideration is 17.5 years, beginning with the date of commercial operation, for all qualifying facilities, except that the minimum financing period before reconsideration of the previously approved capacity charges is for the duration of the financing for a qualifying facility that produces electric energy by the use of biomass, waste, wood, hydroelectric, wind, and other renewable resources, or any combination of renewable resources, as the primary energy source.

(c) Disallow net increased costs attributable to a generating plant outage of more than 90 days in duration unless the utility demonstrates by clear and satisfactory evidence that the outage, or any part of the outage, was not caused or prolonged by the utility’s negligence or by unreasonable or imprudent management.

(d) Disallow transportation costs attributable to capital investments to develop a utility’s capability to transport fuel or relocate fuel at the utility’s facilities and disallow unloading and handling expenses incurred after receipt of fuel by the utility.

(e) Disallow the cost of fuel purchased from an affiliated company to the extent that the fuel is more costly than fuel of requisite quality available at or about the same time from other suppliers with whom it would be comparably cost beneficial to deal.

(f) Disallow charges unreasonably or imprudently incurred for fuel not taken.

(g) Disallow additional costs resulting from unreasonably or imprudently renegotiated fuel contracts.

(h) Disallow penalty charges unreasonably or imprudently incurred.

(i) Disallow demurrage charges.

(j) Disallow increases in charges for nuclear fuel disposal unless the utility has received the prior approval of the commission.

(14) In its order in a power supply cost reconciliation, the commission shall require an electric utility to refund to customers or credit to customers’ bills any net amount determined to have been recovered over the period covered in excess of the amounts determined to have been actually expensed by the utility for power supply, and to have been incurred through reasonable and prudent actions not precluded by the commission order in the power supply and cost review. The commission shall apportion the refunds or credits among the customers of the utility utilizing procedures that the commission determines to be reasonable. The commission may adopt different procedures with respect to customers served under the various rate schedules of the utility and may, in appropriate circumstances, order refunds or credits in proportion to the excess amounts actually collected from each such customer during the period covered.

(15) In its order in a power supply cost reconciliation, the commission shall authorize an electric utility to recover from customers any net amount by which the amount determined to have been recovered over the period covered was less than the amount determined to have been actually expensed by the utility for power supply, and to have been incurred through reasonable and prudent actions not precluded by the commission order in the power supply and cost review. For excess costs incurred through management actions contrary to the commission’s power supply and cost review order, the commission shall authorize a utility to recover costs incurred for power supply in the reconciliation period in excess of the amount recovered over the period only if the utility demonstrates by clear and convincing evidence that the excess expenses were beyond the ability of the utility to control through reasonable and prudent actions. For excess costs incurred through management actions consistent with the commission’s power supply and cost review order, the commission shall authorize a utility to recover costs incurred for power supply in the reconciliation period in excess of the amount recovered over the period only if the utility demonstrates that the level of those expenses resulted from reasonable and prudent management actions. The amounts in excess of the amounts actually recovered by the utility for power supply shall be apportioned among and charged to the customers of the utility utilizing procedures that the commission determines to be reasonable. The commission may adopt different procedures with respect to customers served under the various rate schedules of the utility and may, in appropriate circumstances, order charges to be made in proportion to the amounts that would have been paid by those customers if the amounts in excess of the amounts actually recovered by the utility for cost of power supply had been included in the power supply cost recovery factors with respect to those customers during the period covered. Charges for the excess amounts shall be spread over a period that the commission determines to be appropriate.

(16) If the commission orders refunds or credits under subsection (14), or additional charges to customers under subsection (15), in its final order in a power supply cost reconciliation, the refunds, credits, or additional charges shall include interest. In determining the interest included in a refund, credit, or additional charge under this subsection, the commission shall consider, to the extent material and practicable, the time at which the excess recoveries or insufficient recoveries, or both occurred. The commission shall determine a rate of interest for excess recoveries, refunds, and credits equal to the greater of the average short-term borrowing rate available to the utility during the appropriate period, or the authorized rate of return on the common stock of the utility during that same period. Costs incurred by the utility for refunds and interest on refunds shall not be charged to customers. The commission shall determine a rate of interest for insufficient recoveries and additional charges equal to the average short-term borrowing rate available to the utility during the appropriate period.

(17) To avoid undue hardship or unduly burdensome or excessive cost, the commission may do both of the following:

(a) Exempt an electric utility with fewer than 200,000 customers in this state from 1 or more of the procedural provisions of this section or may modify the filing requirements of this section.

(b) Exempt an energy utility organized as a cooperative corporation under sections 98 to 109 of 1931 PA 327, MCL 450.98 to 450.109, from 1 or more of the provisions of this section.

(18) Notwithstanding any other provision of this act, the commission may, upon application by an electric utility, set power supply cost recovery factors, in a manner otherwise consistent with this act, in an order resulting from a general rate case. By October 27, 1987, for the purpose of setting power supply cost recovery factors, the commission shall permit an electric utility to reopen a general rate case in which a final order was issued within 120 days before or after June 29, 1987 or to amend an application or reopen the evidentiary record in a pending general rate case. If the commission sets power supply cost recovery factors in an order resulting from a general rate case, all of the following apply:

(a) The power supply cost recovery factors shall cover a future period of 48 months or the number of months that elapse until the commission orders new power supply cost recovery factors in a general rate case, whichever is the shorter period.

(b) The commission shall conduct annual reconciliation proceedings under subsection (12) and if an annual reconciliation proceeding shows a recoverable amount under subsection (15), the commission shall authorize the electric utility to defer the amount and to accumulate interest on the amount under subsection (16), and in the next order resulting from a general rate case authorize the utility to recover the amount and interest from its customers in the manner provided in subsection (15).

(c) The power supply cost recovery factors are not subject to revision under subsection (10).

Sec. 6k. (1) This section governs the initial filing and implementation of a power supply cost recovery plan under section 6j(3).

(2) The initial power supply cost recovery plan may be for a period of less than 12 months and shall be filed as follows:

(a) By an electric utility subject to commission rate jurisdiction with at least 200,000 residential customers in the state of Michigan, by February 13, 1983.

(b) By all other electric utilities subject to commission rate jurisdiction, by January 13, 1984 in accordance with the provisions of this act which the commission determines to be appropriate for the individual utility.

(3) Notwithstanding section 6a(5), until the expiration of 3 months plus the remainder of the then current billing month following the last day on which a utility is required to file its first power supply cost recovery plan under subsection (2), the utility may alter its rate schedule in accordance with an existing fuel cost adjustment clause or purchased and net interchanged power adjustment clause. Thereafter, the utility may make charges in excess of base rates for the cost of power supply pursuant only to subsections (2) and (4). After October 13, 1982, any revenues resulting from an existing fuel cost adjustment clause or purchased and net interchanged power adjustment clause and recorded for an annual reconciliation period ending before January 1, 1983, by an electric utility are subject to the existing reconciliation proceeding established by the commission for the utility. In this proceeding, the commission shall consider the reasonableness and prudence of expenditures charged pursuant to an existing fuel cost adjustment clause or purchased and net interchanged power adjustment clause after October 13, 1982. On and after January 1, 1983, all fuel cost and purchased and net interchanged power revenues received by an electric utility, whether included in base rates or collected pursuant to a fuel or purchased and net interchanged power adjustment clause or a power supply cost recovery clause, are subject to annual reconciliation with the cost of fuel and purchased and net interchanged power. The annual reconciliations shall be conducted in accordance with the reconciliation procedures described in section 6j(12) to (18), including the provisions for refunds, additional charges, deferral and recovery, and shall include consideration by the commission of the reasonableness and prudence of expenditures charged pursuant to any fuel or purchased and net interchanged power adjustment clause in existence during the period being reconciled. If the utility has a lag correction provision included in its existing adjustment clauses, the commission shall allow any adjustment to rates attributable to that lag correction provision to be implemented for the 3 billing months immediately succeeding the final billing month in which the existing adjustment clauses as operative.

(4) Until the commission approves or disapproves a power supply cost recovery clause in a final commission order in a contested case required by section 6j(2), a utility that had a fuel cost adjustment clause or purchased and net interchanged power adjustment clause on October 13, 1982 and which has applied for a power supply cost recovery clause under section 6j may adjust its rates under section 6j(3) to (18), to include power supply cost recovery factors.

Sec. 6l. (1) For purposes of implementing sections 6a, 6h, 6j, 6s, and 6t, this section and section 6m provide a means of insuring equitable representation of the interests of energy utility customers.

(2) As used in this section and section 6m:

(a) “Annual receipts” means the payments received by the fund under section 6m(2)(a), (b), (c), and (d) during a calendar year.

(b) “Board” means the utility consumer participation board created under subsection (3).

(c) “Commission” means the Michigan public service commission.

(d) “Department” means the department of licensing and regulatory affairs.

(e) “Energy cost recovery proceeding” means any proceeding to establish or implement a gas cost recovery clause or a power supply cost recovery clause as provided in section 6h or 6j, to set gas cost recovery factors under section 6h(17), or to set power supply cost recovery factors under section 6j(18).

(f) “Energy utility” means each electric or gas company regulated by the commission.

(g) “Fund” means the utility consumer representation fund created in section 6m.

(h) “Household” means a single-family home, duplex, mobile home, seasonal dwelling, farm home, cooperative, condominium, or apartment that has normal household facilities such as a bathroom, individual cooking facilities, and kitchen sink facilities. Household does not include a penal or corrective institution, or a motel, hotel, or other similar structure if used as a transient dwelling.

(i) “Jurisdictional” means subject to rate regulation by the commission.

(j) “Net grant proceeds” means the annual receipts of the fund less the amounts reserved for the attorney general’s use and the amounts expended for board expenses and operation.

(k) “Residential energy utility consumer” or “consumer” means a customer of an energy utility who receives utility service for use within an individual household or an improvement reasonably appurtenant to and normally associated with an individual household.

(l) “Residential tariff sales” means those sales by an energy utility that are subject to residential tariffs on file with the commission.

(m) “Utility consuming industry” means a person, sole proprietorship, partnership, association, corporation, or other entity that receives utility service ordinarily and primarily for use in connection with the manufacture, sale, or distribution of goods or the provision of services, but does not include a nonprofit organization representing residential utility customers.

(3) The utility consumer participation board is created within the department and shall exercise its powers and duties under this act independently of the department. The procurement and related management functions of the board shall be performed under the direction and supervision of the department. The board shall consist of 5 members appointed by the governor, 1 of whom shall be chosen from 1 or more lists of qualified persons submitted by the attorney general.

(4) For the purposes of subsection (5) only, “utility” means an electric or gas company located in or outside of this state.

(5) Each member of the board shall meet the following requirements:

(a) Shall be an advocate for the interests of residential utility consumers, as demonstrated by the member’s knowledge of and support for consumer interests and concerns in general or specifically related to utility matters.

(b) Shall not be, or shall not have been within the 5 years preceding appointment, a member of a governing body of, or employed in a managerial or professional or consulting capacity by a utility or an association representing utilities; an enterprise or professional practice that received over $1,500.00 in the year preceding the appointment as a supplier of goods or services to a utility or association representing utilities; or an organization representing employees of such a utility, association, enterprise, or professional practice, or an association that represents such an organization.

(c) Shall not have, or shall not have had within 1 year preceding appointment, a financial interest exceeding $1,500.00 in a utility, an association representing utilities, or an enterprise or professional practice that received over $1,500.00 in the year preceding the appointment as a supplier of goods or services to a utility or association representing utilities.

(d) Shall not be an officer or director of an applicant for a grant under section 6m.

(e) Shall not be a member of the immediate family of an individual who would be ineligible under subdivision (a), (b), (c), or (d).

(6) The members of the board shall be appointed for 2-year terms beginning with the first day of a legislative session in an odd-numbered year and ending on the day before the first day of the legislative session in the next odd-numbered year or when the members’ successors are appointed, whichever occurs later. The governor shall not appoint a member to the board for a term commencing after the governor’s term of office has ended. A vacancy shall be filled in the same manner as the original appointment. If the vacancy is created other than by expiration of a term, the member shall be appointed for the balance of the unexpired term of the member to be succeeded.

(7) The governor shall remove a member of the board if that member is absent for any reason from either 3 consecutive board meetings or more than 50% of the meetings held by the board in a calendar year. However, an individual who is removed due to absenteeism is eligible for reappointment to fill a vacancy that occurs in the board membership. The governor also shall remove a member of the board if the member is subsequently determined to be ineligible under subsection (5).

(8) The board shall hold bimonthly meetings and additional meetings as necessary. A quorum consists of 3 members. A majority vote of the members appointed and serving is necessary for a decision. At its first meeting following the appointment of new members, or as soon as possible after the first meeting, the board shall elect biennially from its membership a chairperson and a vice-chairperson.

(9) The board shall not act directly to represent the interests of residential utility consumers except through administration of the fund and grant program under this section.

(10) The business that the board may perform shall be conducted at a public meeting of the board held in compliance with the open meetings act, 1976 PA 267, MCL 15.261 to 15.275. Public notice of the time, date, and place of the meeting shall be given in the manner required by the open meetings act, 1976 PA 267, MCL 15.261 to 15.275.

(11) A writing prepared, owned, used, in the possession of, or retained by the board in the performance of an official function shall be made available to the public in compliance with the freedom of information act, 1976 PA 442, MCL 15.231 to 15.246.

(12) A member of the board may be reimbursed for actual and necessary expenses, including travel expenses to and from each meeting held by the board, incurred in discharging the member’s duties under this section and section 6m. In addition to expense reimbursement, a board member may receive remuneration from the board of $100.00 per meeting attended, not to exceed $1,000.00 in a calendar year. These limits shall be adjusted proportionately to an adjustment in the remittance amounts under section 6m(4) to allow for changes in the cost of living.

Sec. 6m. (1) The utility consumer representation fund is created as a special fund. The state treasurer shall be the custodian of the fund and shall maintain a separate account of the money in the fund. The money in the fund shall be invested in the bonds, notes, and other evidences of indebtedness issued or insured by the United States government and its agencies, and in prime commercial paper. The state treasurer shall release money from the fund, including interest earned, in the manner and at the time directed by the board.

(2) Except as provided in subsection (5), each energy utility that has applied to the commission for the initiation of an energy cost recovery proceeding shall remit to the fund before or upon filing its initial application for that proceeding, and on or before the first anniversary of that application, an amount of money determined by the board in the following manner:

(a) In the case of an energy utility company serving at least 100,000 customers in this state, its proportional share of $900,000.00 adjusted annually by a factor as provided in subsection (4). This adjusted amount shall become the new base amount to which the factor provided in subsection (4) is applied in the succeeding year. A utility’s proportional share shall be calculated by dividing the company’s jurisdictional total operating revenues for the preceding year, as stated in its annual report, by the total operating revenues for the preceding year of all energy utility companies serving at least 100,000 customers in this state. This amount shall be made available by the board for use by the attorney general for the purposes described in subsection (16).

(b) In the case of an energy utility company serving at least 100,000 residential customers in this state, its proportional share of $650,000.00 adjusted annually by a factor as provided in subsection (4). This adjusted amount shall become the new base amount to which the factor provided in subsection (4) is applied in the succeeding year. A utility’s proportional share shall be calculated by dividing the company’s jurisdictional gross revenues from residential tariff sales for the preceding year by the gross revenues from residential tariff sales for the preceding year of all energy utility companies serving at least 100,000 residential customers in this state. This amount shall be used for grants under subsection (10).

(c) In the case of an energy utility company serving fewer than 100,000 customers in this state, its proportional share of $100,000.00 adjusted annually by a factor as provided in subsection (4). This adjusted amount shall become the new base amount to which the factor provided in subsection (4) is applied in the succeeding year. A utility’s proportional share shall be calculated by dividing the company’s jurisdictional total operating revenues for the preceding year, as stated in its annual report, by the total operating revenues for the preceding year of all energy utility companies serving fewer than 100,000 customers in this state. This amount shall be made available by the board for use by the attorney general for the purposes described in subsection (16).

(d) In the case of an energy utility company serving fewer than 100,000 residential customers in this state, its proportional share of $100,000.00 adjusted annually by a factor as provided in subsection (4). This adjusted amount shall become the new base amount to which the factor provided in subsection (4) is applied in the succeeding year. A utility’s proportional share shall be calculated by dividing the company’s jurisdictional gross revenues from residential tariff sales for the preceding year by the gross revenues from residential tariff sales for the preceding year of all energy utility companies serving fewer than 100,000 residential customers in this state. This amount shall be used for grants under subsection (10).

(3) Payments made by an energy utility under subsection (2)(a) or (c) are operating expenses of the utility that the commission shall permit the utility to charge to its customers. Payments made by a utility under subsection (2)(b) or (d) are operating expenses of the utility that the commission shall permit the utility to charge to its residential customers.

(4) For purposes of subsection (2), the board shall set the factor at a level not to exceed the percentage increase in the index known as the consumer price index for urban wage earners and clerical workers, select areas, all items indexed, for the Detroit standard metropolitan statistical area, compiled by the Bureau of Labor Statistics of the United States Department of Labor, or any successor agency, that has occurred between January of the preceding year and January of the year in which the payment is required to be made. In the event that more than 1 such index is compiled, the index yielding the largest payment shall be the maximum allowable factor. The board shall advise utilities of the factor.

(5) The remittance requirements of this section do not apply to an energy utility organized as a cooperative corporation under sections 98 to 109 of 1931 PA 327, MCL 450.98 to 450.109, and grants from the fund shall not be used to participate in an energy cost recovery proceeding primarily affecting such a utility.

(6) In the event of a dispute between the board and an energy utility about the amount of payment due, the utility shall pay the undisputed amount and, if the utility and the board cannot agree, the board may initiate civil action in the circuit court for Ingham County for recovery of the disputed amount. The commission shall not accept or take action on an application for an energy cost recovery proceeding from an energy utility subject to this section that has not fully paid undisputed remittances required by this section.

(7) The commission shall not accept or take action on an application for an energy cost recovery proceeding from an energy utility subject to this section until 30 days after it has been notified by the board that the board is ready to process grant applications, will transfer funds payable to the attorney general immediately upon the receipt of those funds, and will within 30 days approve grants and remit funds to qualified grant applicants.

(8) The board may accept a gift or grant from any source to be deposited in the fund if the conditions or purposes of the gift or grant are consistent with this section.

(9) The costs of operation and expenses incurred by the board in performing its duties under this section and section 6l, including remuneration to board members, shall be paid from the fund. A maximum of 5% of the annual receipts of the fund may be budgeted and used to pay expenses other than grants made under subsection (10).

(10) The net grant proceeds shall finance a grant program from which the board may award to an applicant an amount that the board determines shall be used for the purposes set forth in this section.

(11) The board shall create and make available to applicants an application form. Each applicant shall indicate on the application how the applicant meets the eligibility requirements provided for in this section and how the applicant proposes to use a grant from the fund to participate in 1 or more proceedings as authorized in subsection (16) that have been or are expected to be filed. Each applicant shall also identify on the application any additional funds or resources, other than the grant funds being requested, that are to be used to participate in the proceeding for which the grant is being requested and how those funds or resources will be utilized. The board shall receive an application requesting a grant from the fund only from a nonprofit organization or a unit of local government in this state. The board shall consider only applications for grants containing proposals that are consistent with subsections (16) and (17) and that serve the interests of residential utility consumers. For purposes of making grants, the board may consider energy conservation, energy waste reduction, demand response, and rate design options to encourage energy conservation, energy waste reduction, and demand response, as well as the maintenance of adequate energy resources. The board shall not consider an application that primarily benefits the applicant or a service provided or administered by the applicant. The board shall not consider an application from a nonprofit organization if 1 of the organization’s principal interests or unifying principles is the welfare of a utility or its investors or employees, or the welfare of 1 or more businesses or industries, other than farms not owned or operated by a corporation, that receive utility service ordinarily and primarily for use in connection with the profit-seeking manufacture, sale, or distribution of goods or services. Mere ownership of securities by a nonprofit organization or its members does not disqualify an application submitted by that organization.

(12) The board shall encourage the representation of the interests of identifiable types of residential utility consumers whose interests may differ, including various social and economic classes and areas of the state, and if necessary, may make grants to more than 1 applicant whose applications are related to a similar issue to achieve this type of representation. In addition, the board shall consider and balance the following criteria in determining whether to make a grant to an applicant:

(a) Evidence of the applicant’s competence, experience, and commitment to advancing the interests of residential utility consumers.

(b) The anticipated involvement of the attorney general in a proceeding and whether activities of the applicant will be duplicative or supplemental to those of the attorney general.

(c) In the case of a nongovernmental applicant, the extent to which the applicant is representative of or has a previous history of advocating the interests of citizens, especially residential utility consumers.

(d) The anticipated effect of the proposal contained in the application on residential utility consumers, including the immediate and long-term impacts of the proposal.

(e) Evidence demonstrating the potential for continuity of effort and the development of expertise in relation to the proposal contained in the application.

(f) The uniqueness or innovativeness of an applicant’s position or point of view as it relates to advocating for residential utility consumers concerning energy costs or rates, and the probability and desirability of that position or point of view prevailing.

(13) As an alternative to choosing between 2 or more applications that have similar proposals, the board may invite 2 or more of the applicants to file jointly and award a grant to be managed cooperatively.

(14) The board shall make disbursements pursuant to a grant in advance of an applicant’s proposed actions as set forth in the application if necessary to enable the applicant to initiate, continue, or complete the proposed actions.

(15) Any notice to utility customers and the general public of hearings or other state proceedings in which grants from the fund may be used shall contain a notice of the availability of the fund and the address of the board.

(16) The annual receipts and interest earned, less administrative costs, may be used only for participation in administrative and judicial proceedings under sections 6a, 6h, 6j, 6s, and 6t, and in federal administrative and judicial proceedings that directly affect the energy costs or rates paid by energy utility customers in this state. Amounts that have been in the fund more than 12 months may be retained in the fund for future proceedings and any unexpended money in the fund shall be reserved to fulfill the purposes for which it was appropriated or may be returned to energy utility companies or used to offset their future remittances in proportion to their previous remittances to the fund, as the board and attorney general determine will best serve the interests of consumers.

(17) The following conditions apply to all grants from the fund:

(a) Disbursements from the fund may be used only to advocate the interests of residential energy utility customers concerning energy costs or rates and not for representation of merely individual interests.

(b) The board shall attempt to maintain a reasonable relationship between the payments from a particular energy utility and the benefits to consumers of that utility.

(c) The board shall coordinate the funded activities of grant recipients with those of the attorney general to avoid duplication of effort, particularly as it relates to the hiring of expert witnesses, to promote supplementation of effort, and to maximize the number of hearings and proceedings with intervenor participation.

(18) A recipient of a grant under subsection (10) may use the grant only for the advancement of the proposed action approved by the board, including, but not limited to, costs of staff, hired consultants and counsel, and research.

(19) A recipient of a grant under subsection (10) shall prepare for and participate in all discussions among the parties designed to facilitate settlement or narrowing of the contested issues before a hearing in order to minimize litigation costs for all parties.

(20) A recipient of a grant under subsection (10) shall file a report with the board within 90 days following the end of the year or a shorter period for which the grant is made. The report shall be made in a form prescribed by the board and is subject to audit by the board. The board shall include each report received under this subsection as part of the board’s annual report required under subsection (22). The report under this subsection shall include the following information:

(a) An account of all grant expenditures made by the grant recipient. Expenditures shall be reported within the following categories:

(i) Employee and contract for services costs.

(ii) Costs of materials and supplies.

(iii) Filing fees and other costs required to effectively represent residential utility consumers as provided in this section.

(b) A detailed list of the regulatory issues raised by the grant recipient and how each issue was determined by the commission, court, or other tribunal.

(c) Any additional information concerning uses of the grant required by the board.

(21) On or before July 1 of each year, the attorney general shall file a report with the house and senate committees on appropriations and the house and senate committees with jurisdiction over energy and utility policy issues. The report shall include the following information:

(a) An account of all expenditures made by the attorney general of money received under this section. Expenditures shall be reported within the following categories:

(i) Employee and contract for services costs.

(ii) Costs of materials and supplies.

(iii) Filing fees and other costs required to effectively represent utility consumers as provided in this section.

(b) Any additional information concerning uses of the money received under this section required by the committees.

(22) On or before July 1 of each calendar year, the board shall submit a detailed report to the house and senate committees with jurisdiction over energy and utility policy issues regarding the discharge of duties and responsibilities under this section and section 6l during the preceding calendar year.

Sec. 6s. (1) An electric utility that proposes to construct an electric generation facility, make a significant investment in an existing electric generation facility, purchase an existing electric generation facility, or enter into a power purchase agreement for the purchase of electric capacity for a period of 6 years or longer may submit an application to the commission seeking a certificate of necessity for that construction, investment, or purchase if that construction, investment, or purchase costs $100,000,000.00 or more and a portion of the costs would be allocable to retail customers in this state. A significant investment in an electric generation facility includes a group of investments reasonably planned to be made over a multiple year period not to exceed 6 years for a singular purpose such as increasing the capacity of an existing electric generation plant. The commission shall not issue a certificate of necessity under this section for any environmental upgrades to existing electric generation facilities. If the application is for the construction of an electric generation facility of 225 megawatts or more or for the construction of an additional generating unit or units totaling 225 megawatts or more at an existing electric generation facility submitted as required under section 6t(13), the commission shall consolidate its proceedings under section 6t and this section. If the commission approves or denies an application for an electric generation facility under this section that has been submitted as required under section 6t(13), the provisions of this section prevail in a conflict with section 6t.

(2) The commission may implement separate review criteria and approval standards for electric utilities with less than 1,000,000 retail customers that seek a certificate of necessity for projects costing less than $100,000,000.00.

(3) An electric utility submitting an application under this section may request 1 or more of the following:

(a) A certificate of necessity that the power to be supplied as a result of the proposed construction, investment, or purchase is needed.

(b) A certificate of necessity that the size, fuel type, and other design characteristics of the existing or proposed electric generation facility or the terms of the power purchase agreement represent the most reasonable and prudent means of meeting that power need.

(c) A certificate of necessity that the price specified in the power purchase agreement will be recovered in rates from the electric utility’s customers.

(d) A certificate of necessity that the estimated purchase or capital costs of and the financing plan for the existing or proposed electric generation facility, including, but not limited to, the costs of siting and licensing a new facility and the estimated cost of power from the new or proposed electric generation facility, will be recoverable in rates from the electric utility’s customers subject to subsection (4)(c).

(4) Within 270 days after the filing of an application under this section, or, for an application for an electric generation facility submitted as required under section 6t(13), concurrently with a final order issued under section 6t, the commission shall issue an order granting or denying the requested certificate of necessity. The commission shall hold a hearing on the application. The hearing shall be conducted as a contested case pursuant to chapter 4 of the administrative procedures act of 1969, 1969 PA 306, MCL 24.271 to 24.287. The commission may allow intervention by persons under the rules of practice and procedure of the commission and shall allow intervention by existing suppliers of electric generation capacity under subsection (13), persons allowed to intervene in the contested case under section 6t, and interested persons. The commission shall permit reasonable discovery before and during the hearing in order to assist parties and interested persons in obtaining evidence concerning the application, including, but not limited to, the reasonableness and prudence of the construction, investment, or purchase for which the certificate of necessity has been requested. The commission shall grant the request if it determines all of the following:

(a) That the electric utility has demonstrated a need for the power that would be supplied by the existing or proposed electric generation facility or pursuant to the proposed power purchase agreement through its approved integrated resource plan under section 6t or subsection (11).

(b) The information supplied indicates that the existing or proposed electric generation facility will comply with all applicable state and federal environmental standards, laws, and rules.

(c) The estimated cost of power from the existing or proposed electric generation facility or the price of power specified in the proposed power purchase agreement is reasonable. The commission shall find that the cost is reasonable if, in the construction or investment in a new or existing facility, to the extent it is commercially practicable, the estimated costs are the result of competitively bid engineering, procurement, and construction contracts, or in a power purchase agreement, the cost is the result of a competitive solicitation. Up to 150 days after an electric utility makes its initial filing, it may file to update its cost estimates if they have materially changed. No other aspect of the initial filing may be modified unless the application is withdrawn and refiled. A utility’s filing updating its cost estimates does not extend the period for the commission to issue an order granting or denying a certificate of necessity. An affiliate of an electric utility that serves customers in this state and at least 1 other state may participate in the competitive bidding to provide engineering, procurement, and construction services to that electric utility for a project covered by this section.

(d) The existing or proposed electric generation facility or proposed power purchase agreement represents the most reasonable and prudent means of meeting the power need relative to other resource options for meeting power demand, including energy efficiency programs, electric transmission efficiencies, and any alternative proposals submitted under this section by existing suppliers of electric generation capacity under subsection (13) or other intervenors.

(e) To the extent practicable, the construction or investment in a new or existing facility in this state is completed using a workforce composed of residents of this state as determined by the commission. This subdivision does not apply to a facility that is located in a county that lies on the border with another state.

(5) The commission may consider any other costs or information related to the costs associated with the power that would be supplied by the existing or proposed electric generation facility or pursuant to the proposed purchase agreement or alternatives to the proposal raised by intervening parties.

(6) In a certificate of necessity under this section, the commission shall specify the costs approved for the construction of or significant investment in the electric generation facility, the price approved for the purchase of the existing electric generation facility, or the price approved for the purchase of power pursuant to the terms of the power purchase agreement. For power purchase agreements that an electric utility enters into with an entity that is not affiliated with that electric utility after the effective date of the amendatory act that added section 6t, the commission shall consider and may authorize a financial incentive for that utility that does not exceed the electric utility’s weighted average cost of capital.

(7) The utility shall annually file, or more frequent if required by the commission, reports to the commission regarding the status of any project for which a certificate of necessity has been granted under subsection (4), including an update concerning the cost and schedule of that project.

(8) If the commission denies any of the relief requested by an electric utility, the electric utility may withdraw its application or proceed with the proposed construction, purchase, investment, or power purchase agreement without a certificate and the assurances granted under this section.

(9) Once the electric generation facility or power purchase agreement is considered used and useful or as otherwise provided in subsection (12), the commission shall include in an electric utility’s retail rates all reasonable and prudent costs for an electric generation facility or power purchase agreement for which a certificate of necessity has been granted. The commission shall not disallow recovery of costs an electric utility incurs in constructing, investing in, or purchasing an electric generation facility or in purchasing power pursuant to a power purchase agreement for which a certificate of necessity has been granted, if the costs do not exceed the costs approved by the commission in the certificate. The portion of the cost of a plant, facility, or power purchase agreement that exceeds the cost approved by the commission is presumed to have been incurred due to a lack of prudence. Once the electric generation facility or power purchase agreement is considered used and useful or as otherwise provided in subsection (12), the commission shall include in the electric utility’s retail rates costs actually incurred by the electric utility that exceed the costs approved by the commission only if the commission finds by a preponderance of the evidence that the additional costs were prudently incurred. The commission shall disallow costs the commission finds have been incurred as the result of fraud, concealment, gross mismanagement, or lack of quality controls amounting to gross mismanagement. The commission shall also require refunds with interest to ratepayers of any of these costs already recovered through the electric utility’s rates and charges. If the assumptions underlying an approved certificate of necessity, other than a certificate of necessity approved for a power purchase agreement for the purchase of electric capacity, materially change, an electric utility may request, or the commission on its own motion may initiate, a proceeding to review whether it is reasonable and prudent to complete an unfinished project for which a certificate of necessity has been granted. If the commission finds that completion of the project is no longer reasonable and prudent, the commission may modify or cancel approval of the certificate of necessity. Except for costs the commission finds an electric utility has incurred as the result of fraud, concealment, gross mismanagement, or lack of quality controls amounting to gross mismanagement, if commission approval is modified or canceled, the commission shall not disallow reasonable and prudent costs already incurred or committed to by contract by an electric utility. Once the commission finds that completion of the project is no longer reasonable and prudent, the commission may limit future cost recovery to those costs that could not be reasonably avoided.

(10) The commission shall adopt standard application filing forms and instructions for use in all requests for a certificate of necessity under this section. The commission may modify the standard application filing forms and instructions adopted under this section.

(11) The commission shall establish standards for an integrated resource plan that shall be filed by an electric utility requesting a certificate of necessity under this section. This subsection does not apply to an electric utility that has an approved integrated resource plan under section 6t. An integrated resource plan shall include all of the following:

(a) A long-term forecast of the electric utility’s load growth under various reasonable scenarios.

(b) The type of generation technology proposed for the generation facility and the proposed capacity of the generation facility, including projected fuel and regulatory costs under various reasonable scenarios.

(c) Projected energy and capacity purchased or produced by the electric utility under any renewable portfolio standard.

(d) Projected energy efficiency program savings under any energy efficiency program requirements and the projected costs for that program.

(e) Projected load management and demand response savings for the electric utility and the projected costs for those programs.

(f) An analysis of the availability and costs of other electric resources that could defer, displace, or partially displace the proposed generation facility or purchased power agreement, including additional renewable energy, energy efficiency programs, load management, and demand response, beyond those amounts contained in subdivisions (c) to (e).

(g) Electric transmission options for the electric utility.

(12) The commission may allow financing interest cost recovery in an electric utility’s base rates on construction work in progress for capital improvements approved under this section prior to the assets being considered used and useful. Regardless of whether or not the commission authorizes base rate treatment for construction work in progress financing interest expense, an electric utility shall be allowed to recognize, accrue, and defer the allowance for funds used during construction.

(13) An existing supplier of electric generation capacity currently producing at least 200 megawatts of firm electric generation capacity resources located in the independent system operator’s zone in which the utility’s load is served that seeks to provide electric generation capacity resources to the utility may submit a written proposal directly to the commission as an alternative to the construction, investment, or purchase for which the certificate of necessity is sought under this section. The entity submitting an alternative proposal under this subsection has standing to intervene and the commission shall allow reasonable discovery in the contested case proceeding conducted under this section. In evaluating an alternative proposal, the commission shall consider the cost of the alternative proposal and the submitting entity’s qualifications, technical competence, capability, reliability, creditworthiness, and past performance. In reviewing an application, the commission may consider any alternative proposals submitted under this subsection. This subsection does not limit the ability of any other person to submit to the commission an alternative proposal to the construction, investment, or purchase for which a certificate of necessity is sought under this section and to petition for and be granted leave to intervene in the contested case proceeding conducted under this section under the rules of practice and procedure of the commission. This subsection does not authorize the commission to order or otherwise require an electric utility to adopt any alternative proposal submitted under this subsection.

(14) An order of the commission following a hearing under this section is subject to judicial review as provided under section 28 of article VI of the state constitution of 1963 and chapter 6 of the administrative procedures act of 1969, 1969 PA 306, MCL 24.301 to 24.306, except that the filing of a petition for review must be filed in the court of appeals within 30 days after the order of the commission is issued and the court shall conduct the review as expeditiously as possible with lawful precedence over other matters.

Sec. 6t. (1) The commission shall, within 120 days of the effective date of the amendatory act that added this section and every 5 years thereafter, commence a proceeding and, in consultation with the Michigan agency for energy, the department of environmental quality, and other interested parties, do all of the following as part of the proceeding:

(a) Conduct an assessment of the potential for energy waste reduction in this state, based on what is economically and technologically feasible, as well as what is reasonably achievable.

(b) Conduct an assessment for the use of demand response programs in this state, based on what is economically and technologically feasible, as well as what is reasonably achievable. The assessment shall expressly account for advanced metering infrastructure that has already been installed in this state and seek to fully maximize potential benefits to ratepayers in lowering utility bills.

(c) Identify significant state or federal environmental regulations, laws, or rules and how each regulation, law, or rule would affect electric utilities in this state.

(d) Identify any formally proposed state or federal environmental regulation, law, or rule that has been published in the Michigan Register or the Federal Register and how the proposed regulation, law, or rule would affect electric utilities in this state.

(e) Identify any required planning reserve margins and local clearing requirements in areas of this state.

(f) Establish the modeling scenarios and assumptions each electric utility should include in addition to its own scenarios and assumptions in developing its integrated resource plan filed under subsection (3), including, but not limited to, all of the following:

(i) Any required planning reserve margins and local clearing requirements.

(ii) All applicable state and federal environmental regulations, laws, and rules identified in this subsection.

(iii) Any supply-side and demand-side resources that reasonably could address any need for additional generation capacity, including, but not limited to, the type of generation technology for any proposed generation facility, projected energy waste reduction savings, and projected load management and demand response savings.

(iv) Any regional infrastructure limitations in this state.

(v) The projected costs of different types of fuel used for electric generation.

(g) Allow other state agencies to provide input regarding any other regulatory requirements that should be included in modeling scenarios or assumptions.

(h) Publish a copy of the proposed modeling scenarios and assumptions to be used in integrated resource plans on the commission’s website.

(i) Before issuing the final modeling scenarios and assumptions each electric utility should include in developing its integrated resource plan, receive written comments and hold hearings to solicit public input regarding the proposed modeling scenarios and assumptions.

(2) A proceeding commenced under subsection (1) shall be completed within 120 days, and shall not be a contested case under chapter 4 of the administrative procedures act of 1969, 1969 PA 306, MCL 24.271 to 24.287. The determination of the modeling assumptions for integrated resource plans made under subsection (1) is not considered a final order for purposes of judicial review. The determinations made under subsection (1) are only subject to judicial review as part of the final commission order approving an integrated resource plan under this section.

(3) Not later than 2 years after the effective date of the amendatory act that added this section, each electric utility whose rates are regulated by the commission shall file with the commission an integrated resource plan that provides a 5-year, 10-year, and 15-year projection of the utility’s load obligations and a plan to meet those obligations, to meet the utility’s requirements to provide generation reliability, including meeting planning reserve margin and local clearing requirements determined by the commission or the appropriate independent system operator, and to meet all applicable state and federal reliability and environmental regulations over the ensuing term of the plan. The commission shall issue an order establishing filing requirements, including application forms and instructions, and filing deadlines for an integrated resource plan filed by an electric utility whose rates are regulated by the commission. The electric utility’s plan may include alternative modeling scenarios and assumptions in addition to those identified under subsection (1).

(4) For an electric utility with fewer than 1,000,000 customers in this state whose rates are regulated by the commission, the commission may issue an order implementing separate filing requirements, review criteria, and approval standards that differ from those established under subsection (3). An electric utility providing electric tariff service to customers both in this state and in at least 1 other state may design its integrated resource plan to cover all its customers on that multistate basis. If an electric utility has filed a multistate integrated resource plan that includes its service area in this state with the relevant utility regulatory commission in another state in which it provides tariff service to retail customers, the commission shall accept that integrated resource plan filing for filing purposes in this state. However, the commission may require supplemental information if necessary as part of its evaluation and determination of whether to approve the plan. Upon request of an electric utility, the commission may adjust the filing dates for a multistate integrated resource plan filing in this state to place its review on the same timeline as other relevant state reviews.

(5) An integrated resource plan shall include all of the following:

(a) A long-term forecast of the electric utility’s sales and peak demand under various reasonable scenarios.

(b) The type of generation technology proposed for a generation facility contained in the plan and the proposed capacity of the generation facility, including projected fuel costs under various reasonable scenarios.

(c) Projected energy purchased or produced by the electric utility from a renewable energy resource. If the level of renewable energy purchased or produced is projected to drop over the planning periods set forth in subsection (3), the electric utility must demonstrate why the reduction is in the best interest of ratepayers.

(d) Details regarding the utility’s plan to eliminate energy waste, including the total amount of energy waste reduction expected to be achieved annually, the cost of the plan, and the expected savings for its retail customers.

(e) An analysis of how the combined amounts of renewable energy and energy waste reduction achieved under the plan compare to the renewable energy resources and energy waste reduction goal provided in section 1 of the clean and renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1001. This analysis and comparison may include renewable energy and capacity in any form, including generating electricity from renewable energy systems for sale to retail customers or purchasing or otherwise acquiring renewable energy credits with or without associated renewable energy, allowed under section 27 of the clean and renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1027, as it existed before the effective date of the amendatory act that added this section.

(f) Projected load management and demand response savings for the electric utility and the projected costs for those programs.

(g) Projected energy and capacity purchased or produced by the electric utility from a cogeneration resource.

(h) An analysis of potential new or upgraded electric transmission options for the electric utility.

(i) Data regarding the utility’s current generation portfolio, including the age, capacity factor, licensing status, and remaining estimated time of operation for each facility in the portfolio.

(j) Plans for meeting current and future capacity needs with the cost estimates for all proposed construction and major investments, including any transmission or distribution infrastructure that would be required to support the proposed construction or investment, and power purchase agreements.

(k) An analysis of the cost, capacity factor, and viability of all reasonable options available to meet projected energy and capacity needs, including, but not limited to, existing electric generation facilities in this state.

(l) Projected rate impact for the periods covered by the plan.

(m) How the utility will comply with all applicable state and federal environmental regulations, laws, and rules, and the projected costs of complying with those regulations, laws, and rules.

(n) A forecast of the utility’s peak demand and details regarding the amount of peak demand reduction the utility expects to achieve and the actions the utility proposes to take in order to achieve that peak demand reduction.

(o) The projected long-term firm gas transportation contracts or natural gas storage the electric utility will hold to provide an adequate supply of natural gas to any new generation facility.

(6) Before filing an integrated resource plan under this section, each electric utility whose rates are regulated by the commission shall issue a request for proposals to provide any new supply-side generation capacity resources needed to serve the utility’s reasonably projected electric load, applicable planning reserve margin, and local clearing requirement for its customers in this state and customers the utility serves in other states during the initial 3-year planning period to be considered in each integrated resource plan to be filed under this section. An electric utility shall define qualifying performance standards, contract terms, technical competence, capability, reliability, creditworthiness, past performance, and other criteria that responses and respondents to the request for proposals must meet in order to be considered by the utility in its integrated resource plan to be filed under this section. Respondents to a request for proposals may request that certain proprietary information be exempt from public disclosure as allowed by the commission. A utility that issues a request for proposals under this subsection shall use the resulting proposals to inform its integrated resource plan filed under this section and include all of the submitted proposals as attachments to its integrated resource plan filing regardless of whether the proposals met the qualifying performance standards, contract terms, technical competence, capability, reliability, creditworthiness, past performance, or other criteria specified for the utility’s request for proposals under this section. An existing supplier of electric generation capacity currently producing at least 200 megawatts of firm electric generation capacity resources located in the independent system operator’s zone in which the utility’s load is served that seeks to provide electric generation capacity resources to the utility may submit a written proposal directly to the commission as an alternative to any supply-side generation capacity resource included in the electric utility’s integrated resource plan submitted under this section, and has standing to intervene in the contested case proceeding conducted under this section. This subsection does not require an entity that submits an alternative under this subsection to submit an integrated resource plan. This subsection does not limit the ability of any other person to submit to the commission an alternative proposal to any supply-side generation capacity resource included in the electric utility’s integrated resource plan submitted under this section and to petition for and be granted leave to intervene in the contested case proceeding conducted under this section under the rules of practice and procedure of the commission. The commission shall only consider an alternative proposal submitted under this subsection as part of its approval process under subsection (8). The electric utility submitting an integrated resource plan under this section is not required to adopt any proposals submitted under this subsection. To the extent practicable, each electric utility is encouraged, but not required, to partner with other electric providers in the same local resource zone as the utility’s load is served in the development of any new supply-side generation capacity resources included as part of its integrated resource plan.

(7) Not later than 300 days after an electric utility files an integrated resource plan under this section, the commission shall state if the commission has any recommended changes, and if so, describe them in sufficient detail to allow their incorporation in the integrated resource plan. If the commission does not recommend changes, it shall issue a final, appealable order approving or denying the plan filed by the electric utility. If the commission recommends changes, the commission shall set a schedule allowing parties at least 15 days after that recommendation to file comments regarding those recommendations, and allowing the electric utility at least 30 days to consider the recommended changes and submit a revised integrated resource plan that incorporates 1 or more of the recommended changes. If the electric utility submits a revised integrated resource plan under this section, the commission shall issue a final, appealable order approving the plan as revised by the electric utility or denying the plan. The commission shall issue a final, appealable order no later than 360 days after an electric utility files an integrated resource plan under this section. Up to 150 days after an electric utility makes its initial filing, the electric utility may file to update its cost estimates if those cost estimates have materially changed. A utility shall not modify any other aspect of the initial filing unless the utility withdraws and refiles the application. A utility’s filing updating its cost estimates does not extend the period for the commission to issue an order approving or denying the integrated resource plan. The commission shall review the integrated resource plan in a contested case proceeding conducted pursuant to chapter 4 of the administrative procedures act of 1969, 1969 PA 306, MCL 24.271 to 24.287. The commission shall allow intervention by interested persons including electric customers of the utility, respondents to the utility’s request for proposals under this section, or other parties approved by the commission. The commission shall request an advisory opinion from the department of environmental quality regarding whether any potential decrease in emissions of sulfur dioxide, oxides of nitrogen, mercury, and particulate matter would reasonably be expected to result if the integrated resource plan proposed by the electric utility under subsection (3) was approved and whether the integrated resource plan can reasonably be expected to achieve compliance with the regulations, laws, or rules identified in subsection (1). The commission may take official notice of the opinion issued by the department of environmental quality under this subsection pursuant to R 792.10428 of the Michigan Administrative Code. Information submitted by the department of environmental quality under this subsection is advisory and is not binding on future determinations by the department of environmental quality or the commission in any proceeding or permitting process. This section does not prevent an electric utility from applying for, or receiving, any necessary permits from the department of environmental quality. The commission may invite other state agencies to provide testimony regarding other relevant regulatory requirements related to the integrated resource plan. The commission shall permit reasonable discovery after an integrated resource plan is filed and during the hearing in order to assist parties and interested persons in obtaining evidence concerning the integrated resource plan, including, but not limited to, the reasonableness and prudence of the plan and alternatives to the plan raised by intervening parties.

(8) The commission shall approve the integrated resource plan under subsection (7) if the commission determines all of the following:

(a) The proposed integrated resource plan represents the most reasonable and prudent means of meeting the electric utility’s energy and capacity needs. To determine whether the integrated resource plan is the most reasonable and prudent means of meeting energy and capacity needs, the commission shall consider whether the plan appropriately balances all of the following factors:

(i) Resource adequacy and capacity to serve anticipated peak electric load, applicable planning reserve margin, and local clearing requirement.

(ii) Compliance with applicable state and federal environmental regulations.

(iii) Competitive pricing.

(iv) Reliability.

(v) Commodity price risks.

(vi) Diversity of generation supply.

(vii) Whether the proposed levels of peak load reduction and energy waste reduction are reasonable and cost effective. Exceeding the renewable energy resources and energy waste reduction goal in section 1 of the clean and renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1001, by a utility shall not, in and of itself, be grounds for determining that the proposed levels of peak load reduction, renewable energy, and energy waste reduction are not reasonable and cost effective.

(b) To the extent practicable, the construction or investment in a new or existing capacity resource in this state is completed using a workforce composed of residents of this state as determined by the commission. This subdivision does not apply to a capacity resource that is located in a county that lies on the border with another state.

(c) The plan meets the requirements of subsection (5).

(9) If the commission denies a utility’s integrated resource plan, the utility, within 60 days after the date of the final order denying the integrated resource plan, may submit revisions to the integrated resource plan to the commission for approval. The commission shall commence a new contested case hearing under chapter 4 of the administrative procedures act of 1969, 1969 PA 306, MCL 24.271 to 24.287. Not later than 90 days after the date that the utility submits the revised integrated resource plan to the commission under this subsection, the commission shall issue an order approving or denying, with recommendations, the revised integrated resource plan if the revisions are not substantial or inconsistent with the original integrated resource plan filed under this section. If the revisions are substantial or inconsistent with the original integrated resource plan, the commission has up to 150 days to issue an order approving or denying, with recommendations, the revised integrated resource plan.

(10) If the commission denies an electric utility’s integrated resource plan, the electric utility may proceed with a proposed construction, purchase, investment, or power purchase agreement contained in the integrated resource plan without the assurances granted under this section.

(11) In approving an integrated resource plan under this section, the commission shall specify the costs approved for the construction of or significant investment in an electric generation facility, the purchase of an existing electric generation facility, the purchase of power under the terms of the power purchase agreement, or other investments or resources used to meet energy and capacity needs that are included in the approved integrated resource plan. The costs for specifically identified investments, including the costs for facilities under subsection (12), included in an approved integrated resource plan that are commenced within 3 years after the commission’s order approving the initial plan, amended plan, or plan review are considered reasonable and prudent for cost recovery purposes.

(12) Except as otherwise provided in subsection (13), for a new electric generation facility approved in an integrated resource plan that is to be owned by the electric utility and that is commenced within 3 years after the commission’s order approving the plan, the commission shall finalize the approved costs for the facility only after the utility has done all of the following and filed the results, analysis, and recommendations with the commission:

(a) Implemented a competitive bidding process for all major engineering, procurement, and construction contracts associated with the construction of the facility.

(b) Implemented a competitive bidding process that allows third parties to submit firm and binding bids for the construction of an electric generation facility on behalf of the utility that would meet all of the technical, commercial, and other specifications required by the utility for the generation facility, such that ownership of the electric generation facility vests with the utility no later than the date the electric generation facility becomes commercially available.

(c) Demonstrated to the commission that the finalized costs for the new electric generation facility are not significantly higher than the initially approved costs under subsection (11). If the finalized costs are found to be significantly higher than the initially approved costs, the commission shall review and approve the proposed costs if the commission determines those costs are reasonable and prudent.

(13) If the capacity resource under subsection (12) is for the construction of an electric generation facility of 225 megawatts or more or for the construction of an additional generating unit or units totaling 225 megawatts or more at an existing electric generation facility, the utility shall submit an application to the commission seeking a certificate of necessity under section 6s.

(14) An electric utility shall annually, or more frequently if required by the commission, file reports to the commission regarding the status of any projects included in the initial 3-year period of an integrated resource plan approved under subsection (7).

(15) For power purchase agreements that a utility enters into after the effective date of the amendatory act that added this section with an entity that is not affiliated with that utility, the commission shall consider and may authorize a financial incentive for that utility that does not exceed the utility’s weighted average cost of capital.

(16) Notwithstanding any other provision of law, an order by the commission approving an integrated resource plan may be reviewed by the court of appeals upon a filing by a party to the commission proceeding within 30 days after the order is issued. All appeals of the order shall be heard and determined as expeditiously as possible with lawful precedence over other matters. Review on appeal shall be based solely on the record before the commission and briefs to the court and is limited to whether the order conforms to the constitution and laws of this state and the United States and is within the authority of the commission under this act.

(17) The commission shall include in an electric utility’s retail rates all reasonable and prudent costs specified under subsections (11) and (12) that have been incurred to implement an integrated resource plan approved by the commission. The commission shall not disallow recovery of costs an electric utility incurs in implementing an approved integrated resource plan, if the costs do not exceed the costs approved by the commission under subsections (11) and (12). If the actual costs incurred by the electric utility exceed the costs approved by the commission, the electric utility has the burden of proving by a preponderance of the evidence that the costs are reasonable and prudent. The portion of the cost of a plant, facility, power purchase agreement, or other investment in a resource that meets a demonstrated need for capacity that exceeds the cost approved by the commission is presumed to have been incurred due to a lack of prudence. The commission may include any or all of the portion of the cost in excess of the cost approved by the commission if the commission finds by a preponderance of the evidence that the costs are reasonable and prudent. The commission shall disallow costs the commission finds have been incurred as the result of fraud, concealment, gross mismanagement, or lack of quality controls amounting to gross mismanagement. The commission shall also require refunds with interest to ratepayers of any of these costs already recovered through the electric utility’s rates and charges. If the assumptions underlying an approved integrated resource plan materially change, or if the commission believes it is unlikely that a project or program will become commercially operational, an electric utility may request, or the commission on its own motion may initiate, a proceeding to review whether it is reasonable and prudent to complete an unfinished project or program included in an approved integrated resource plan. If the commission finds that completion of the project or program is no longer reasonable and prudent, the commission may modify or cancel approval of the project or program and unincurred costs in the electric utility’s integrated resource plan. Except for costs the commission finds an electric utility has incurred as the result of fraud, concealment, gross mismanagement, or lack of quality controls amounting to gross mismanagement, if commission approval is modified or canceled, the commission shall not disallow reasonable and prudent costs already incurred or committed to by contract by an electric utility. Once the commission finds that completion of the project or program is no longer reasonable and prudent, the commission may limit future cost recovery to those costs that could not be reasonably avoided.

(18) The commission may allow financing interest cost recovery in an electric utility’s base rates on construction work in progress for capital improvements approved under this section prior to the assets’ being considered used and useful. Regardless of whether or not the commission authorizes base rate treatment for construction work in progress financing interest expense, an electric utility may recognize, accrue, and defer the allowance for funds used during construction.

(19) An electric utility may seek to amend an approved integrated resource plan. Except as otherwise provided under this subsection, the commission shall consider the amendments under the same process and standards that govern the review and approval of a revised integrated resource plan under subsection (9). The commission may order an electric utility that seeks to amend an approved integrated resource plan under this subsection to file a plan review under subsection (21).

(20) An electric utility shall file an application for review of its integrated resource plan not later than 5 years after the effective date of the most recent commission order approving a plan, a plan amendment, or a plan review. The commission shall consider a plan review under the same process and standards established in this section for review and approval of an integrated resource plan. A commission order approving a plan review has the same effect as an order approving an integrated resource plan.

(21) The commission may, on its own motion or at the request of the electric utility, order an electric utility to file a plan review. The department of environmental quality may request the commission to order a plan review to address material changes in environmental regulations and requirements that occur after the commission’s approval of an integrated resource plan. An electric utility must file a plan review within 270 days after the commission orders the utility to file a plan review.

(22) As used in this section, “long-term firm gas transportation” means a binding agreement entered into between the electric utility and a natural gas transmission provider for a set period of time to provide firm delivery of natural gas to an electric generation facility.

Sec. 6u. (1) Not later than 90 days after the effective date of the amendatory act that added this section, the commission shall commence a study in collaboration with representatives of each customer class, utilities whose rates are regulated by the commission, and other interested parties regarding performance-based regulation, under which a utility’s authorized rate of return would depend on the utility achieving targeted policy outcomes.

(2) In the study required under this section, the commission shall review performance-based regulation systems that have been implemented in another state or country, including, but not limited to, the RIIO (revenue = incentives + innovation + outputs) model utilized in the United Kingdom.

(3) In reviewing various performance-based regulation systems, the commission shall evaluate, but not be limited to, all of the following factors:

(a) Methods for estimating the revenue needed by a utility during a multiyear pricing period, and a fair return, that uses forecasts of efficient total expenditures by the utility instead of distinguishing between operating and capital costs.

(b) Methods to increase the length of time between rate cases, to provide utilities with more opportunity to retain cost savings without the threat of imminent rate adjustments, and to encourage utilities to make investments that have extended payback periods.

(c) Options for establishing incentives and penalties that pertain to issues such as customer satisfaction, safety, reliability, environmental impact, and social obligations.

(d) Profit-sharing provisions that can spread efficiency gains among consumers and utility shareholders and can reduce the degree of downside risk associated with attempts at innovation.

(4) Not later than 1 year after the effective date of the amendatory act that added this section, the commission shall report and make recommendations in writing to the legislature and governor based on the result of the study conducted under this section.

(5) This section does not limit the commission’s authority to authorize performance-based regulation.

Sec. 6v. (1) Notwithstanding any existing power purchase agreement, the commission shall, at least every 5 years, conduct a proceeding, as a contested case pursuant to chapter 4 of the administrative procedures act of 1969, 1969 PA 306, MCL 24.271 to 24.287, to reevaluate the procedures and rates schedules including avoided cost rates, as originally established by the commission in an order dated March 17, 1981 in case no. U-6798, to implement title II, section 210, of the public utility regulatory policies act of 1978, as it relates to qualifying facilities from which utilities in this state have an obligation to purchase energy and capacity. Nothing in this section supersedes the provisions of PURPA or the Federal Energy Regulatory Commission’s regulations and orders implementing PURPA.

(2) In setting rates for avoided costs, the commission shall take into consideration the factors regarding avoided costs set forth in PURPA and the Federal Energy Regulatory Commission’s regulations and orders implementing PURPA.

(3) After an initial contested case under subsection (1), for a utility serving less than 1,000,000 electric customers in this state, the commission may conduct any periodic reevaluations of the procedures, rate schedules, and avoided cost rates for that utility using notice and comment procedures instead of a full contested case. The commission shall conduct the periodic reevaluation in a contested case under chapter 4 of the administrative procedures act of 1969, 1969 PA 306, MCL 24.271 to 24.287, if a qualifying facility files a comment disputing the utility filing and requesting a contested case.

(4) An order issued by the commission under subsection (1) shall do all of the following:

(a) Ensure that the rates for purchases by an electric utility from, and rates for sales to, a qualifying facility shall, over the term of a contract, be just and reasonable and in the public interest, as defined by PURPA.

(b) Ensure that an electric utility does not discriminate against a qualifying facility with respect to the conditions or price for provision of maintenance power, backup power, interruptible power, and supplementary power or for any other service.

(c) Require that any prices charged by an electric utility for maintenance power, backup power, interruptible power, and supplementary power and all other such services are cost-based and just and reasonable.

(d) Establish a schedule of avoided cost price updates for each electric utility.

(e) Require electric utilities to publish on their websites template contracts for power purchase agreements for qualifying facilities of less than 3 megawatts that need not include terms for either price or duration of the contract. The terms of a template contract published under this subsection are not binding on either an electric utility or a qualifying facility and may be negotiated and altered upon agreement between an electric utility and a qualifying facility.

(5) Within 1 year after the effective date of the amendatory act that added this section, and every 2 years thereafter, the commission shall issue a report to the Michigan agency for energy and the standing committees of the senate and house of representatives with primary responsibility for energy and environmental issues. The report shall provide a description and status of qualifying facilities in this state, the current status of power purchase agreements of each qualifying facility, and the commission’s efforts to comply with the requirements of PURPA.

(6) As used in this section:

(a) “Avoided costs” means that term as defined in 18 CFR 292.101.

(b) “Backup power” means electric energy or capacity supplied by an electric utility to replace electric energy ordinarily generated by a qualifying facility’s own electric generation equipment during an unscheduled outage of the qualifying facility.

(c) “Maintenance power” means electric energy or capacity supplied by an electric utility during scheduled outages of the qualifying facility.

(d) “PURPA” means title II, section 210, of the public utility regulatory policies act of 1978.

(e) “Qualifying facility” or “facilities” means qualifying cogeneration facilities or qualifying small power production facilities from which an electric utility within this state has an obligation to purchase energy and capacity within the meaning of sections 201 and 210 of PURPA, 16 USC 796 and 824a-3, and associated federal regulations and orders.

(f) “Supplementary power” means electric energy or capacity supplied by an electric utility, regularly used by a qualifying facility in addition to the electric energy or capacity that the qualifying facility generates.

Sec. 6w. (1) If the appropriate independent system operator receives approval from the Federal Energy Regulatory Commission to implement a resource adequacy tariff that provides for a capacity forward auction, and includes the option for a state to implement a prevailing state compensation mechanism for capacity, then the commission shall examine whether the prevailing state compensation mechanism would be more cost-effective, reasonable, and prudent than the capacity forward auction for this state before the commission may order the prevailing state compensation mechanism to be implemented in any utility service territory in which the prevailing state compensation mechanism is not yet effective. Before the commission orders the implementation of the prevailing state compensation mechanism in 1 or more utility service territories, the commission shall hold a contested case hearing pursuant to chapter 4 of the administrative procedures act of 1969, 1969 PA 306, MCL 24.271 to 24.287. The commission shall allow intervention by interested persons, alternative electric suppliers, and customers of alternative electric suppliers and the utility under consideration. At the conclusion of the proceeding, the commission shall make a finding for each utility service territory under consideration, based on clear and convincing evidence, as to whether or not the prevailing state compensation mechanism would be more cost-effective, reasonable, and prudent than the use of the capacity forward auction for this state in meeting the local clearing requirement and the planning reserve margin requirement. The contested case must be scheduled for completion by December 1 before the independent system operator’s capacity forward auction for this state, and the commission’s decision shall identify which utility service territories will be subject to the prevailing state compensation mechanism. If the commission implements the prevailing state compensation mechanism, it shall implement the prevailing state compensation mechanism for a minimum of 4 consecutive planning years unless such period conflicts with the federal tariff. The commission shall establish the charge as a capacity charge under subsection (3) and determine that charge consistent with the approved resource adequacy tariff of the appropriate independent system operator.

(2) If the appropriate independent system operator receives approval from the Federal Energy Regulatory Commission to implement a resource adequacy tariff that provides for a capacity forward auction, and does not include the option for a state to implement a prevailing state compensation mechanism for capacity, then the commission shall examine whether a state reliability mechanism established under subsection (8) would be more cost-effective, reasonable, and prudent than the capacity forward auction for this state before the commission may order the state reliability mechanism to be implemented in any utility service territory. Before the commission orders the implementation of the state reliability mechanism in 1 or more utility service territories, the commission shall hold a contested case hearing pursuant to chapter 4 of the administrative procedures act of 1969, 1969 PA 306, MCL 24.271 to 24.287. The commission shall allow intervention by interested persons, alternative electric suppliers, and customers of alternative electric suppliers and the utility under consideration. At the conclusion of the proceeding, the commission shall make a finding for each utility service territory under consideration, based on clear and convincing evidence, as to whether or not the state reliability mechanism would be more cost-effective, reasonable, and prudent than the use of the capacity forward auction for this state in meeting the local clearing requirement and the planning reserve margin requirement. The contested case must be scheduled for completion by December 1 before the independent system operator’s capacity forward auction for this state, and the commission’s decision shall identify which utility service territories will be subject to the state reliability mechanism. If, by September 30, 2017, the Federal Energy Regulatory Commission does not put into effect a resource adequacy tariff that includes a capacity forward auction or a prevailing state compensation mechanism, then the commission shall establish a state reliability mechanism under subsection (8). The commission may commence a proceeding before October 1 if the commission believes orderly administration would be enabled by doing so. If the commission implements a state reliability mechanism, it shall be for a minimum of 4 consecutive planning years beginning in the upcoming planning year. A state reliability charge must be established in the same manner as a capacity charge under subsection (3) and be determined consistent with subsection (8).

(3) After the effective date of the amendatory act that added section 6t, the commission shall establish a capacity charge as provided in this section. A determination of a capacity charge must be conducted as a contested case pursuant to chapter 4 of the administrative procedures act of 1969, 1969 PA 306, MCL 24.271 to 24.287, after providing interested persons with notice and a reasonable opportunity for a full and complete hearing and conclude by December 1 of each year. The commission shall allow intervention by interested persons, alternative electric suppliers, and customers of alternative electric suppliers and the utility under consideration. The commission shall provide notice to the public of the single capacity charge as determined for each territory. No new capacity charge is required to be paid before June 1, 2018. The capacity charge must be applied to alternative electric load that is not exempt as set forth under subsections (6) and (7). If the commission elects to implement a capacity forward auction for this state as set forth in subsection (1) or (2), then a capacity charge shall not apply beginning in the first year that the capacity forward auction for this state is effective. In order to ensure that noncapacity electric generation services are not included in the capacity charge, in determining the capacity charge, the commission shall do both of the following and ensure that the resulting capacity charge does not differ for full service load and alternative electric supplier load:

(a) For the applicable term of the capacity charge, include the capacity-related generation costs included in the utility’s base rates, surcharges, and power supply cost recovery factors, regardless of whether those costs result from utility ownership of the capacity resources or the purchase or lease of the capacity resource from a third party.

(b) For the applicable term of the capacity charge, subtract all non-capacity-related electric generation costs, including, but not limited to, costs previously set for recovery through net stranded cost recovery and securitization and the projected revenues, net of projected fuel costs, from all of the following:

(i) All energy market sales.

(ii) Off-system energy sales.

(iii) Ancillary services sales.

(iv) Energy sales under unit-specific bilateral contracts.

(4) The commission shall provide for a true-up mechanism that results in a utility charge or credit for the difference between the projected net revenues described in subsection (3) and the actual net revenues reflected in the capacity charge. The true-up shall be reflected in the capacity charge in the subsequent year. The methodology used to set the capacity charge shall be the same methodology used in the true-up for the applicable planning year.

(5) Not less than once every year, the commission shall review or amend the capacity charge in all subsequent rate cases, power supply cost recovery cases, or separate proceedings established for that purpose.

(6) A capacity charge shall not be assessed for any portion of capacity obligations for each planning year for which an alternative electric supplier can demonstrate that it can meet its capacity obligations through owned or contractual rights to any resource that the appropriate independent system operator allows to meet the capacity obligation of the electric provider. The preceding sentence shall not be applied in any way that conflicts with a federal resource adequacy tariff, when applicable. Any electric provider that has previously demonstrated that it can meet all or a portion of its capacity obligations shall give notice to the commission by September 1 of the year 4 years before the beginning of the applicable planning year if it does not expect to meet that capacity obligation and instead expects to pay a capacity charge. The capacity charge in the utility service territory must be paid for the portion of its load taking service from the alternative electric supplier not covered by capacity as set forth in this subsection during the period that any such capacity charge is effective.

(7) An electric provider shall provide capacity to meet the capacity obligation for the portion of that load taking service from an alternative electric supplier in the electric provider’s service territory that is covered by the capacity charge during the period that any such capacity charge is effective. The alternative electric supplier has the obligation to provide capacity for the portion of the load for which the alternative electric supplier has demonstrated an ability to meet its capacity obligations. If an alternative electric supplier ceases to provide service for a portion or all of its load, it shall allow, at a cost no higher than the determined capacity charge, the assignment of any right to that capacity in the applicable planning year to whatever electric provider accepts that load.

(8) If a state reliability mechanism is required to be established under subsection (2), the commission shall do all of the following:

(a) Require, by December 1 of each year, that each electric utility demonstrate to the commission, in a format determined by the commission, that for the planning year beginning 4 years after the beginning of the current planning year, the electric utility owns or has contractual rights to sufficient capacity to meet its capacity obligations as set by the appropriate independent system operator, or commission, as applicable.

(b) Require, by the seventh business day of February each year, that each alternative electric supplier, cooperative electric utility, or municipally owned electric utility demonstrate to the commission, in a format determined by the commission, that for the planning year beginning 4 years after the beginning of the current planning year, the alternative electric supplier, cooperative electric utility, or municipally owned electric utility owns or has contractual rights to sufficient capacity to meet its capacity obligations as set by the appropriate independent system operator, or commission, as applicable. One or more municipally owned electric utilities may aggregate their capacity resources that are located in the same local resource zone to meet the requirements of this subdivision. One or more cooperative electric utilities may aggregate their capacity resources that are located in the same local resource zone to meet the requirements of this subdivision. A cooperative or municipally owned electric utility may meet the requirements of this subdivision through any resource, including a resource acquired through a capacity forward auction, that the appropriate independent system operator allows to qualify for meeting the local clearing requirement. A cooperative or municipally owned electric utility’s payment of an auction price related to a capacity deficiency as part of a capacity forward auction conducted by the appropriate independent system operator does not by itself satisfy the resource adequacy requirements of this section unless the appropriate independent system operator can directly tie that provider’s payment to a capacity resource that meets the requirements of this subsection. By the seventh business day of February in 2018, an alternative electric supplier shall demonstrate to the commission, in a format determined by the commission, that for the planning year beginning June 1, 2018, and the subsequent 3 planning years, the alternative electric supplier owns or has contractual rights to sufficient capacity to meet its capacity obligations as set by the appropriate independent system operator, or commission, as applicable. If the commission finds an electric provider has failed to demonstrate it can meet a portion or all of its capacity obligation, the commission shall do all of the following:

(i) For alternative electric load, require the payment of a capacity charge that is determined, assessed, and applied in the same manner as under subsection (3) for that portion of the load not covered as set forth in subsections (6) and (7). If a capacity charge is required to be paid under this subdivision in the planning year beginning June 1, 2018 or any of the 3 subsequent planning years, the capacity charge is applicable for each of those planning years.

(ii) For a cooperative or municipally owned electric utility, recommend to the attorney general that suit be brought consistent with the provisions of subsection (9) to require that procurement.

(iii) For an electric utility, require any audits and reporting as the commission considers necessary to determine if sufficient capacity is procured. If an electric utility fails to meet its capacity obligations, the commission may assess appropriate and reasonable fines, penalties, and customer refunds under this act.

(c) In order to determine the capacity obligations, request that the appropriate independent system operator provide technical assistance in determining the local clearing requirement and planning reserve margin requirement. If the appropriate independent system operator declines, or has not made a determination by October 1 of that year, the commission shall set any required local clearing requirement and planning reserve margin requirement, consistent with federal reliability requirements.

(d) In order to determine if resources put forward will meet such federal reliability requirements, request technical assistance from the appropriate independent system operator to assist with assessing resources to ensure that any resources will meet federal reliability requirements. If the technical assistance is rendered, the commission shall accept the appropriate independent system operator’s determinations unless it finds adequate justification to deviate from the determinations related to the qualification of resources. If the appropriate independent system operator declines, or has not made a determination by February 28, the commission shall make those determinations.

(9) The attorney general or any customer of a municipally owned electric utility or cooperative electric utility may commence a civil action for injunctive relief against that municipally owned electric utility or cooperative electric utility if the municipally owned electric utility or cooperative electric utility fails to meet the applicable requirements of subsection (8)(b). The attorney general or customer shall commence an action under this subsection in the circuit court for the county in which the principal office of the municipally owned electric utility or cooperative electric utility is located. The attorney general or customer shall not file an action under this subsection unless the attorney general or customer gives the municipally owned electric utility or cooperative electric utility at least 60 days’ written notice of the intent to sue, the basis for the suit, and the relief sought. Within 30 days after the municipally owned electric utility or cooperative electric utility receives written notice of the intent to sue, the municipally owned electric utility or cooperative electric utility and the attorney general or customer shall meet and make a good-faith attempt to determine if there is a credible basis for the action. The municipally owned electric utility or cooperative electric utility shall take all reasonable and prudent steps necessary to comply with the applicable requirements of subsection (8)(b) within 90 days after the meeting if there is a credible basis for the action. If the parties do not agree as to whether there is a credible basis for the action, the attorney general or customer may proceed to file the suit.

(10) The commission shall adjust the dates under this section if needed to ensure proper alignment with the appropriate independent system operator’s procedures and requirements. However, any changes to the dates in this section must ensure that providers still meet applicable reliability requirements. The commission shall not permit a capacity charge to be assessed under this section for any year in which it has elected the capacity forward auction instead of the prevailing state compensation mechanism or the state reliability mechanism.

(11) Nothing in this act shall prevent the commission from determining a generation capacity charge under the reliability assurance agreement, rate schedule FERC No. 44 of the independent system operator known as PJM Interconnection, LLC, as approved by the Federal Energy Regulatory Commission in docket no. ER10-2710 or similar successor tariff.

(12) As used in this section:

(a) “Appropriate independent system operator” means the Midcontinent Independent System Operator.

(b) “Capacity forward auction” means an auction-based resource adequacy construct and the associated tariffs developed by the appropriate independent system operator for at least a portion of this state for 3 years forward or more.

(c) “Electric provider” means any of the following:

(i) Any person or entity that is regulated by the commission for the purpose of selling electricity to retail customers in this state.

(ii) A municipally owned electric utility in this state.

(iii) A cooperative electric utility in this state.

(iv) An alternative electric supplier licensed under section 10a.

(d) “Local clearing requirement” means the amount of capacity resources required to be in the local resource zone in which the electric provider’s demand is served to ensure reliability in that zone as determined by the appropriate independent system operator for the local resource zone in which the electric provider’s demand is served and by the commission under subsection (8).

(e) “Planning reserve margin requirement” means the amount of capacity equal to the forecasted coincident peak demand that occurs when the appropriate independent system operator footprint peak demand occurs plus a reserve margin that meets an acceptable loss of load expectation as set by the commission or the appropriate independent system operator under subsection (8).

(f) “Planning year” means June 1 through the following May 31 of each year.

(g) “Prevailing state compensation mechanism” means an option for a state to elect a prevailing compensation rate for capacity consistent with the requirements of the appropriate independent system operator’s resource adequacy tariff.

(h) “State reliability mechanism” means a plan adopted by the commission in the absence of a prevailing state compensation mechanism to ensure reliability of the electric grid in this state consistent with subsection (8).

Sec. 6x. (1) Subject to section 6a(13), in order to ensure equivalent consideration of energy waste reduction resources within the integrated resource planning process, the commission shall by January 1, 2021 authorize a shared savings mechanism for an electric utility to the extent that the electric utility has not otherwise capitalized the costs of the energy waste reduction, conservation, demand reduction, and other waste reduction measures.

(2) For an electric utility that achieves annual electric energy savings of at least 1% but not greater than 1.25% of its total annual weather-adjusted retail sales in megawatt hours in the previous calendar year, the shared savings incentive shall be 25% of the net benefits validated as a result of the programs implemented by the electric utility related to energy waste reduction, conservation, demand reduction, and other waste reduction. A shared savings mechanism authorized under this subsection shall not exceed 15% of the electric utility’s expenditures associated with implementing energy waste reduction programs for the calendar year in which the shared savings mechanism was authorized. The commission shall determine net benefits by calculating the net present value of the lifetime avoided utility costs that are projected from the utility’s energy waste reduction programs implemented in a calendar year less the utility expenditures associated with implementing the energy waste reduction program in that calendar year, including all overhead and administrative costs. The commission shall calculate net present value by using a discount rate of the utility’s weighted average cost of capital in that calendar year.

(3) For an electric utility that achieves annual electric energy savings of greater than 1.25% but not greater than 1.5% of the total annual weather-adjusted retail sales in megawatt hours in the previous calendar year, the shared savings incentive shall be 27.5% of the net benefits validated as a result of the programs implemented by the electric utility related to energy waste reduction, conservation, demand reduction, and other waste reduction. A shared savings mechanism authorized under this subsection shall not exceed 17.5% of the electric utility’s expenditures associated with implementing energy waste reduction programs for the calendar year in which the shared savings mechanism was authorized. The commission shall determine net benefits by calculating the net present value of the lifetime avoided utility costs that are projected from the utility’s energy waste reduction programs implemented in a calendar year less the utility expenditures associated with implementing the energy waste reduction program in that calendar year, including all overhead and administrative costs. The commission shall calculate net present value by using a discount rate of the utility’s weighted average cost of capital in that calendar year.

(4) For an electric utility that achieves annual electric energy savings greater than 1.5% of the total annual weather-adjusted retail sales in megawatt hours in the previous calendar year, the shared savings incentive shall be 30% of the net benefits validated as a result of the programs implemented by the electric utility related to energy waste reduction, conservation, demand reduction, and other waste reduction. A shared savings mechanism authorized under this subsection shall not exceed 20% of the electric utility’s expenditures associated with implementing energy waste reduction programs for the calendar year in which the shared savings mechanism was authorized. The commission shall determine net benefits by calculating the net present value of the lifetime avoided utility costs that are projected from the utility’s energy waste reduction programs implemented in a calendar year less the utility expenditures associated with implementing the energy waste reduction program in that calendar year, including all overhead and administrative costs. The commission shall calculate net present value by using a discount rate of the utility’s weighted average cost of capital in that calendar year.

Sec. 6z. (1) A covered utility shall not discontinue utility service to a geographic area that the covered utility serves without first filing an abandonment application with the commission and obtaining approval from the commission to discontinue that service after notice and a contested case proceeding. The commission shall not approve any abandonment application filed under this section unless the commission determines that there is clear and convincing evidence that all affected customers would have access to affordable, reliable, and safe utility service from an alternative source. A covered utility does not have to file an abandonment application under this section if utility service is being discontinued to a specific parcel or parcels to enable another covered utility to provide service that the other covered utility is legally permitted to provide. As used in this subsection, “covered utility” means any of the following:

(a) A cooperative electric utility subject to the commission’s jurisdiction for its service area, distribution performance standards, and quality of service.

(b) A rural gas cooperative.

(c) An electric utility, natural gas utility, or steam utility subject to the commission’s rate-making jurisdiction.

(2) Not less than 30 days after an electric utility files a proposal to retire an electric generating plant with a regional transmission organization, the utility shall provide that proposal in its entirety to the commission.

(3) Not less than 60 days before an electric utility applies to the operating reliability subcommittee of the North American Electric Reliability Corporation for approval of a proposal to revise an existing load balancing authority, the electric utility shall do both of the following:

(a) File with the commission a full and complete report of the proposed revision.

(b) Serve a copy of the report required to be filed with the commission under subdivision (a) on all other electric utilities in this state.

Sec. 10. The purpose of sections 10a through 10bb is to do all of the following:

(a) To ensure that all persons in this state are afforded safe, reliable electric power at a competitive rate.

(b) To improve the opportunities for economic development in this state and to promote financially healthy and competitive utilities in this state.

(c) To maintain, foster, and encourage robust, reliable, and economic generation, distribution, and transmission systems to provide this state’s electric suppliers and generators an opportunity to access regional sources of generation and wholesale power markets and to ensure a reliable supply of electricity in this state.

Sec. 10a. (1) The commission shall issue orders establishing the rates, terms, and conditions of service that allow retail customers to take service from an alternative electric supplier. The orders shall do all of the following:

(a) Except as otherwise provided in this section, provide that no more than 10% of an electric utility’s average weather-adjusted retail sales for the preceding calendar year may take service from an alternative electric supplier at any time.

(b) Set forth procedures necessary to allocate the amount of load that will be allowed to be served by alternative electric suppliers, through the use of annual energy allotments awarded on a calendar year basis. If the sales of a utility are less in a subsequent year or if the energy usage of a customer receiving electric service from an alternative electric supplier exceeds its annual energy allotment for that facility, that customer shall not be forced to purchase electricity from a utility, but may purchase electricity from an alternative electric supplier for that facility during that calendar year.

(c) Notwithstanding any other provision of this section, provide that, if the commission determines that less than 10% of an electric utility’s average weather-adjusted retail sales for the preceding calendar year is taking service from alternative electric suppliers, the commission shall set as a cap on the weather-adjusted retail sales that may take service from an alternative electric supplier, for the current calendar year and 5 subsequent calendar years, the percentage amount of weather-adjusted retail sales for the preceding calendar year rounded up to the nearest whole percentage. If the cap is not adjusted for 6 consecutive calendar years, the cap shall return to 10% in the calendar year following that sixth consecutive calendar year. If a utility that serves less than 200,000 customers in this state has not had any load served by an alternative electric supplier in the preceding 4 years, the commission shall adjust the cap in accordance with this provision for no more than 2 consecutive calendar years.

(d) Notwithstanding any other provision of this section, customers seeking to expand usage at a facility that has been continuously served through an alternative electric supplier since April 1, 2008 shall be permitted to purchase electricity from an alternative electric supplier for both the existing and any expanded load at that facility as well as any new facility constructed or acquired after October 6, 2008 that is similar in nature if the customer owns more than 50% of the new facility.

(e) Provide that for an existing facility that is receiving 100% of its electric service from an alternative electric supplier on or after the effective date of the amendatory act that added section 6t, the owner of that facility may purchase electricity from an alternative electric supplier, regardless of whether the sales exceed 10% of the servicing electric utility’s average weather-adjusted retail sales, for both the existing electric choice load at that facility and any expanded load arising after the effective date of the amendatory act that added section 6t at that facility as well as any new facility that is similar in nature to the existing facility, that is constructed or acquired by the customer on a site contiguous to the existing site or on a site that would be contiguous to an existing site in the absence of an existing public right-of-way, and the customer owns more than 50% of that facility. This subdivision does not authorize or permit an existing facility being served by an electric utility on standard tariff service on the effective date of the amendatory act that added section 6t to be served by an alternative electric supplier.

(f) Notwithstanding any other provision of this section, any customer operating an iron ore mining facility, iron ore processing facility, or both, located in the Upper Peninsula of this state, may purchase all or any portion of its electricity from an alternative electric supplier, regardless of whether the sales exceed 10% of the serving electric utility’s average weather-adjusted retail sales, if that customer is in compliance with the terms of a settlement agreement requiring it to facilitate construction of a new power plant located in the Upper Peninsula of this state. A customer described in this subdivision and the alternative electric supplier that provides electric service to that customer are not subject to the requirements contained in the amendatory act that added section 6t and any administrative regulations adopted under that amendatory act. The commission’s orders establishing rates, terms, and conditions of retail access service issued before the effective date of the amendatory act that added section 6t remain in effect with regard to retail open access provided under this subdivision.

(g) Provide that a customer on an enrollment queue waiting to take retail open access service as of December 31, 2015 shall continue on the queue and an electric utility shall add a new customer to the queue if the customer’s prospective alternative electric supplier submits an enrollment request to the electric utility. A customer shall be removed from the queue by notifying the electric utility electronically or in writing.

(h) Require each electric utility to file with the commission not later than January 15 of each year a rank-ordered queue of all customers awaiting retail open access service under subdivision (g). The filing must include the estimated amount of electricity used by each customer awaiting retail open access service under subdivision (g). All customer-specific information contained in the filing under this subdivision is exempt from release under the freedom of information act, 1976 PA 442, MCL 15.231 to 15.246, and the commission shall treat that information as confidential information. The commission may release aggregated information as part of its annual report as long as individual customer information or data are not released.

(i) Provide that if the prospective alternative electric supplier of a customer next on the queue awaiting retail open access service is notified after the effective date of the amendatory act that added section 6t that less than 10% of an electric utility’s average weather-adjusted retail sales for the preceding calendar year are taking service from an alternative electric supplier and that the amount of electricity needed to serve the customer’s electric load is available under the 10% allocation, the customer may take service from an alternative electric supplier. The customer’s prospective alternative electric supplier shall notify the electric utility within 5 business days after being notified whether the customer will take service from an alternative electric supplier. If the customer’s prospective alternative electric supplier fails to notify the utility within 5 business days or if the customer chooses not to take retail open access service, the customer shall be removed from the queue of those awaiting retail open access service. The customer may subsequently be added to the queue as a new customer under the provisions of subdivision (g). A customer that elects to take service from an alternative electric supplier under this subdivision shall become service-ready under rules established by the commission and the utility’s approved retail open access service tariffs.

(j) Provide that the commission shall ensure if a customer is notified that the customer’s service from an alternative electric supplier will be terminated or restricted as a result of the alternative electric supplier limiting service in this state, the customer has 60 days to acquire service from a different alternative electric supplier. If the customer is a public entity, the time to acquire services from a different alternative electric supplier shall not be less than 180 days.

(k) Provide that as a condition of licensure, an alternative electric supplier meets all of the requirements of this act.

(2) The commission shall issue orders establishing a licensing procedure for all alternative electric suppliers. To ensure adequate service to customers in this state, the commission shall require that an alternative electric supplier maintain an office within this state, shall assure that an alternative electric supplier has the necessary financial, managerial, and technical capabilities, shall require that an alternative electric supplier maintain records that the commission considers necessary, and shall ensure an alternative electric supplier’s accessibility to the commission, to consumers, and to electric utilities in this state. The commission also shall require alternative electric suppliers to agree that they will collect and remit to local units of government all applicable users, sales, and use taxes. An alternative electric supplier is not required to obtain any certificate, license, or authorization from the commission other than as required by this act.

(3) The commission shall issue orders to ensure that customers in this state are not switched to another supplier or billed for any services without the customer’s consent.

(4) This act does not prohibit or limit the right of a person to obtain self-service power and does not impose a transition, implementation, exit fee, or any other similar charge on self-service power. A person using self-service power is not an electric supplier, electric utility, or a person conducting an electric utility business. As used in this subsection, “self-service power” means any of the following:

(a) Electricity generated and consumed at an industrial site or contiguous industrial site or single commercial establishment or single residence without the use of an electric utility’s transmission and distribution system.

(b) Electricity generated primarily by the use of by-product fuels, including waste water solids, which electricity is consumed as part of a contiguous facility, with the use of an electric utility’s transmission and distribution system, but only if the point or points of receipt of the power within the facility are not greater than 3 miles distant from the point of generation.

(c) A site or facility with load existing on June 5, 2000 that is divided by an inland body of water or by a public highway, road, or street but that otherwise meets this definition meets the contiguous requirement of this subdivision regardless of whether self-service power was being generated on June 5, 2000.

(d) A commercial or industrial facility or single residence that meets the requirements of subdivision (a) or (b) meets this definition whether or not the generation facility is owned by an entity different from the owner of the commercial or industrial site or single residence.

(5) This act does not prohibit or limit the right of a person to engage in affiliate wheeling and does not impose a transition, implementation, exit fee, or any other similar charge on a person engaged in affiliate wheeling.

(6) The rights of parties to existing contracts and agreements in effect as of January 1, 2000 between electric utilities and qualifying facilities, including the right to have the charges recovered from the customers of an electric utility, or its successor, are not abrogated, increased, or diminished by this act, nor shall the receipt of any proceeds of the securitization bonds by an electric utility be a basis for any regulatory disallowance. Further, any securitization or financing order issued by the commission that relates to a qualifying facility’s power purchase contract shall fully consider that qualifying facility’s legal and financial interests.

(7) A customer that elects to receive service from an alternative electric supplier may subsequently provide notice to the electric utility of the customer’s desire to receive standard tariff service from the electric utility under procedures approved by the commission.

(8) The commission shall authorize rates that will ensure that an electric utility that offered retail open access service from 2002 through October 6, 2008 fully recovers its restructuring costs and any associated accrued regulatory assets. This includes, but is not limited to, implementation costs, stranded costs, and costs authorized under section 10d(4) as it existed before October 6, 2008, that have been authorized for recovery by the commission in orders issued before October 6, 2008. The commission shall approve surcharges that will ensure full recovery of all such costs by October 6, 2013.

(9) As used in subsections (1) and (7):

(a) “Customer” means the building or facilities served through a single existing electric billing meter and does not mean the person, corporation, partnership, association, governmental body, or other entity owning or having possession of the building or facilities.

(b) “Standard tariff service” means, for each regulated electric utility, the retail rates, terms, and conditions of service approved by the commission for service to customers who do not elect to receive generation service from alternative electric suppliers.

(10) As used in this section:

(a) “Affiliate” means a person or entity that directly, or indirectly through 1 or more intermediates, controls, is controlled by, or is under common control with another specified entity. As used in this subdivision, “control” means, whether through an ownership, beneficial, contractual, or equitable interest, the possession, directly or indirectly, of the power to direct or to cause the direction of the management or policies of a person or entity or the ownership of at least 7% of an entity either directly or indirectly.

(b) “Affiliate wheeling” means a person’s use of direct access service where an electric utility delivers electricity generated at a person’s industrial site to that person or that person’s affiliate at a location, or general aggregated locations, within this state that was either 1 of the following:

(i) For at least 90 days during the period from January 1, 1996 to October 1, 1999, supplied by self-service power, but only to the extent of the capacity reserved or load served by self-service power during the period.

(ii) Capable of being supplied by a person’s cogeneration capacity within this state that has had since January 1, 1996 a rated capacity of 15 megawatts or less, was placed in service before December 31, 1975, and has been in continuous service since that date. A person engaging in affiliate wheeling is not an electric supplier, an electric utility, or conducting an electric utility business when a person engages in affiliate wheeling.

Sec. 10c. (1) Except for a violation under section 10a(3) and as otherwise provided under this section, upon a complaint or on the commission’s own motion, if the commission finds, after notice and hearing, that an electric utility or an alternative electric supplier has not complied with a provision or order issued under sections 10 through 10ee, or that a natural gas utility has not complied with a provision or order issued under section 10ee, the commission shall order any remedies and penalties necessary to make whole a customer or other person that has suffered damages as a result of the violation, including, but not limited to, 1 or more of the following:

(a) Order the electric utility, natural gas utility, or alternative electric supplier to pay a fine for the first offense of not less than $1,000.00 or more than $20,000.00. For a second offense, the commission shall order the person to pay a fine of not less than $2,000.00 or more than $40,000.00. For a third and any subsequent offense, the commission shall order the person to pay a fine of not less than $5,000.00 or more than $50,000.00.

(b) Order a refund to the customer of any excess charges.

(c) Order any other remedies that would make whole a person harmed, including, but not limited to, payment of reasonable attorney fees.

(d) Revoke the license of the alternative electric supplier if the commission finds a pattern of violations.

(e) Issue cease and desist orders.

(2) Upon a complaint or the commission’s own motion, the commission may conduct a contested case to review allegations of a violation under section 10a(3).

(3) If the commission finds that a person has violated section 10a(3), the commission shall order remedies and penalties to protect customers and other persons that have suffered damages as a result of the violation, including, but not limited to, 1 or more of the following:

(a) Order the person to pay a fine for the first offense of not less than $20,000.00 or more than $30,000.00. For a second and any subsequent offense, the commission shall order the person to pay a fine of not less than $30,000.00 or more than $50,000.00. If the commission finds that the second or any of the subsequent offenses were knowingly made in violation of section 10a(3), the commission shall order the person to pay a fine of not more than $70,000.00. Each unauthorized action made in violation of section 10a(3) is a separate offense under this subdivision.

(b) Order an unauthorized supplier to refund to the customer any amount greater than the customer would have paid to an authorized supplier.

(c) Order an unauthorized supplier to reimburse an authorized supplier an amount equal to the amount paid by the customer that should have been paid to the authorized supplier.

(d) Order the refund of any amounts paid by the customer for unauthorized services.

(e) Order a portion between 10% to 50% of the fine ordered under subdivision (a) be paid directly to the customer that suffered the violation under section 10a(3).

(f) If the person is licensed under this act, revoke the license if the commission finds a pattern of violations of section 10a(3).

(g) Issue cease and desist orders.

(4) Notwithstanding subsection (3), a fine shall not be imposed for a violation of section 10a(3) if the supplier has otherwise fully complied with section 10a(3) and shows that the violation was an unintentional and bona fide error that occurred notwithstanding the maintenance of procedures reasonably adopted to avoid the error. Examples of a bona fide error include clerical, calculation, computer malfunction, programming, or printing errors. An error in legal judgment with respect to a supplier’s obligations under section 10a(3) is not a bona fide error. The burden of proving that a violation was an unintentional and bona fide error is on the supplier.

(5) If the commission finds that a party’s position in a complaint filed under subsection (2) is frivolous, the commission shall award to the prevailing party their costs, including reasonable attorney fees, against the nonprevailing party and their attorney.

Sec. 10f. (1) If, after subtracting the average demand for each retail customer under contract that exceeds 15% of the utility’s retail load in the relevant market, an electric utility has commercial control over more than 30% of the generating capacity available to serve a relevant market, the utility shall do 1 or more of the following with respect to any generation in excess of that required to serve its firm retail sales load, including a reasonable reserve margin:

(a) Divest a portion of its generating capacity.

(b) Sell generating capacity under a contract with a nonretail purchaser for a term of at least 5 years.

(c) Transfer generating capacity to an independent brokering trustee for a term of at least 5 years in blocks of at least 500 megawatts, 24 hours per day.

(2) The total generating capacity available to serve the relevant market shall be determined by the commission and shall equal the sum of the firm available transmission capability into the relevant market and the aggregate generating capacity located within the relevant market, less 1 or more of the following:

(a) If a municipal utility does not permit its retail customers to select alternative electric suppliers, the generating capacity owned by a municipal utility necessary to serve the retail native load.

(b) Generating capacity dedicated to serving on-site load.

(c) The generating capacity of any multistate electric supplier jurisdictionally assigned to customers of other states.

(3) Within 30 days after a commission determination of the total generating capacity under subsection (2) in a relevant market, an electric utility that exceeds the 30% limit shall file an application with the commission for approval of a market power mitigation plan. The commission shall approve the plan if it is consistent with this act or require modifications to the plan to make it consistent with this act. The utility retains the right to determine what specific actions to take to achieve compliance with this section.

(4) An independent brokering trustee shall be completely independent from and have no affiliation with the utility. The terms of any transfer of generating capacity shall ensure that the trustee has complete control over the marketing, pricing, and terms of the transferred capacity for at least 5 years and shall provide appropriate performance incentives to the trustee for marketing the transferred capacity.

(5) Upon application to the commission by the utility, the commission may issue an order approving a change in trustees during the 5-year term upon a showing that a trustee has failed to market the transferred generating capacity in a prudent and experienced manner.

Sec. 10p. (1) Each electric utility operating in this state shall establish an industry worker transition program that, in consultation with employees or applicable collective bargaining representatives, provides skills upgrades, apprenticeship and training programs, voluntary separation packages consistent with reasonable business practices, and job banks to coordinate and assist placement of employees into comparable employment at no less than the wage rates and substantially equivalent fringe benefits received before the transition.

(2) The costs resulting from subsection (1) include audited and verified employee-related restructuring costs that are incurred as a result of 2000 PA 141 or as a result of prior commission restructuring orders, including employee severance costs, employee retraining programs, early retirement programs, outplacement programs, and similar costs and programs, that have been approved and found to be prudently incurred by the commission.

(3) In the event of a sale, purchase, or any other transfer of ownership of 1 or more Michigan divisions or business units, or generating stations or generating units, of an electric utility, to either a third party or a utility subsidiary, the electric utility’s contract and agreements with the acquiring entity or persons shall require all of the following for a period of at least 30 months:

(a) That the acquiring entity or persons hire a sufficient number of nonsupervisory employees to safely and reliably operate and maintain the station, division, or unit by making offers of employment to the nonsupervisory workforce of the electric utility’s division, business unit, generating station, or generating unit.

(b) That the acquiring entity or persons not employ nonsupervisory employees from outside the electric utility’s workforce unless offers of employment have been made to all qualified nonsupervisory employees of the acquired business unit or facility.

(c) That the acquiring entity or persons have a dispute resolution mechanism culminating in a final and binding decision by a neutral third party for resolving employee complaints or disputes over wages, fringe benefits, and working conditions.

(d) That the acquiring entity or persons offer employment at no less than the wage rates and substantially equivalent fringe benefits and terms and conditions of employment that are in effect at the time of transfer of ownership of the division, business unit, generating station, or generating unit. The wage rates and substantially equivalent fringe benefits and terms and conditions of employment shall continue for at least 30 months from the time of the transfer of ownership unless the employees, or where applicable collective bargaining representative, and the new employer mutually agree to different terms and conditions of employment within that 30-month period.

(4) The electric utility shall offer a transition plan to those employees who are not offered jobs by the entity because the entity has a need for fewer workers. If there is litigation concerning the sale, or other transfer of ownership of the electric utility’s divisions, business units, generating stations, or generating units, the 30-month period under subsection (3) begins on the date the acquiring entity or persons take control or management of the divisions, business units, generating stations, or generating units of the electric utility.

(5) The commission shall adopt generally applicable service quality and reliability standards for the transmission, generation, and distribution systems of electric utilities and other entities subject to its jurisdiction, including, but not limited to, standards for service outages, distribution facility upgrades, repairs and maintenance, telephone service, billing service, operational reliability, and public and worker safety. In setting service quality and reliability standards, the commission shall consider safety, costs, local geography and weather, applicable codes, national electric industry practices, sound engineering judgment, and experience. The commission shall also include provisions to upgrade the service quality of distribution circuits that historically have experienced significantly below-average performance in relationship to similar distribution circuits.

(6) Annually, each jurisdictional utility or entity shall file its report with the commission detailing actions to be taken to comply with the service quality and reliability standards during the next calendar year and its performance in relation to the service quality and reliability standards during the prior calendar year. The annual reports shall contain that data as required by the commission, including the estimated cost of achieving improvements in the jurisdictional utility’s or entity’s performance with respect to the service quality and reliability standards.

(7) The commission shall analyze the data to determine whether the jurisdictional entities are properly operating and maintaining their systems and take corrective action if needed.

(8) By December 31, 2009, the commission shall review its existing rules under this section and amend the rules, if needed, under the administrative procedures act of 1969, 1969 PA 306, MCL 24.201 to 24.328, to implement performance standards for generation facilities and for distribution facilities to protect end-use customers from power quality disturbances.

(9) Any standards or rules developed under this section shall be designed to do the following, as applicable:

(a) Establish different requirements for each customer class, whenever those different requirements are appropriate to carry out the provisions of this section, and to reflect different load and service characteristics of each customer class.

(b) Consider the availability and associated cost of necessary equipment and labor required to maintain or upgrade distribution and generating facilities.

(c) Ensure that the most cost-effective means of addressing power quality disturbances are promoted for each utility, including consideration of the installation of equipment or adoption of operating practices at the end-user’s location.

(d) Take into account the extent to which the benefits associated with achieving a specified standard or improvement are offset by the incremental capital, fuel, and operation and maintenance expenses associated with meeting the specified standard or improvement.

(e) Carefully consider the time frame for achieving a specified standard, taking into account the time required to implement needed investments or modify operating practices.

(10) The commission shall also create benchmarks for individual jurisdictional entities within their rate-making process in order to accomplish the goals of this section to alleviate end-use customer power quality disturbances and promote power plant generating cost efficiency.

(11) The commission shall establish a method for gathering data from the industrial customer class to assist in monitoring power quality and reliability standards related to service characteristics of the industrial customer class.

(12) The commission may levy financial incentives and penalties upon any jurisdictional entity which exceeds or fails to meet the service quality and reliability standards.

(13) As used in this section, “jurisdictional utility” or “jurisdictional entity” means a jurisdictional regulated utility as that term is defined in section 6q.

Sec. 10r. (1) The commission shall establish minimum standards for the form and content of all disclosures, explanations, or sales information disseminated by a person selling electric service to ensure that the person provides adequate, accurate, and understandable information about the service that enables a customer to make an informed decision relating to the source and type of electric service purchased. The commission shall develop the standards to do all of the following:

(a) Not be unduly burdensome.

(b) Not unnecessarily delay or inhibit the initiation and development of competition for electric generation service in any market.

(c) Establish different requirements for disclosures, explanations, or sales information relating to different services or similar services to different classes of customers, whenever the different requirements are appropriate to carry out the purposes of this section.

(2) The commission shall require that all electric suppliers disclose in standardized, uniform format on the customer’s bill with a bill insert, on customer contracts, or, for cooperatives, in periodicals issued by an association of rural electric cooperatives, information about the environmental characteristics of electricity products purchased by the customer, including all of the following:

(a) The average fuel mix, including categories for oil, gas, coal, solar, hydroelectric, wind, biofuel, nuclear, solid waste incineration, biomass, and other fuel sources. If a source fits into the other category, the specific source must be disclosed. A regional average, determined by the commission, may be used only for that portion of the electricity purchased by the customer for which the fuel mix cannot be discerned. As used in this subdivision, “biomass” means dedicated crops grown for energy production and organic waste.

(b) The average emissions, in pounds per megawatt hour, sulfur dioxide, carbon dioxide, and oxides of nitrogen. An emissions default, determined by the commission, may be used if the regional average fuel mix is being disclosed.

(c) The average of the high-level nuclear waste generated in pounds per megawatt hour.

(d) The regional average fuel mix and emissions profile as referenced in subdivisions (a), (b), and (c).

(3) The information required by subsection (2) shall be provided no more than twice annually, and be based on a rolling annual average. Emissions factors will be based on annual publicly available data by generation source.

(4) All of the information required to be provided under subsection (1) shall also be provided to the commission to be included on the commission’s internet site.

(5) The Michigan agency for energy shall establish the Michigan renewables energy program. The program shall be designed to inform customers in this state of the availability and value of using renewable energy generation and the potential of reduced pollution. The program shall also be designed to promote the use of existing renewable energy sources and encourage the development of new facilities.

(6) By July 3, 2009, each electric utility regulated by the commission shall file with the commission a plan for utilizing dispatchable customer-owned distributed generation within the context of its integrated resource planning process. Included in the utility’s filing shall be proposals for enrolling and compensating customers for the utility’s right to dispatch at-will the distributed generation assets owned by those customers and provisions requiring the customer to maintain these assets in a dispatchable condition. If an electric utility already has programs addressing the subject of the filing required under this subsection, the utility may refer to and take credit for those existing programs in its proposed plan.

Sec. 10t. (1) An electric utility or alternative electric supplier shall not shut off service to an eligible customer during the heating season for nonpayment of a delinquent account if the customer is an eligible senior citizen customer or if the customer pays to the utility or supplier a monthly amount equal to 7% of the estimated annual bill for the eligible customer and the eligible customer demonstrates, within 14 days of requesting shutoff protection, that he or she has applied for state or federal heating assistance. If an arrearage exists at the time an eligible customer applies for protection from shutoff of service during the heating season, the utility or supplier shall permit the customer to pay the arrearage in equal monthly installments between the date of application and the start of the subsequent heating season.

(2) An electric utility or alternative electric supplier may shut off service to a customer as provided in part 7 of the clean and renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1201 to 460.1211, or to an eligible low-income customer who does not pay the monthly amounts required under subsection (1) after giving notice in the manner required by rules. The utility or supplier is not required to offer a settlement agreement to an eligible low-income customer who fails to make the monthly payments required under subsection (1).

(3) If a customer fails to comply with the terms and conditions of this section, an electric utility may shut off service on its own behalf or on behalf of an alternative electric supplier after giving the customer a notice, by personal service or first-class mail, that contains all of the following information:

(a) That the customer has not paid the per-meter charge described in section 205 of the clean and renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1205, or the customer has defaulted on the winter protection plan.

(b) The nature of the default.

(c) That unless the customer makes the payments that are past due within 10 days of the date of mailing, the utility or supplier may shut off service.

(d) The date on or after which the utility or supplier may shut off service, unless the customer takes appropriate action.

(e) That the customer has the right to file a complaint disputing the claim of the utility or supplier before the date of the proposed shutoff of service.

(f) That the customer has the right to request a hearing before a hearing officer if the complaint cannot be otherwise resolved and that the customer shall pay to the utility or supplier that portion of the bill that is not in dispute within 3 days of the date that the customer requests a hearing.

(g) That the customer has the right to represent himself or herself, to be represented by an attorney, or to be assisted by any other person of his or her choice in the complaint process.

(h) That the utility or supplier will not shut off service pending the resolution of a complaint that is filed with the utility in accordance with this section.

(i) The telephone number and address of the utility or supplier where the customer may make inquiry, enter into a settlement agreement, or file a complaint.

(j) That the customer should contact a social services agency immediately if the customer believes he or she might be eligible for emergency economic assistance.

(k) That the utility or supplier will postpone shutoff of service if a medical emergency exists at the customer’s residence.

(l) That the utility or supplier may require a deposit and restoration charge if the supplier shuts off service for nonpayment of a delinquent account.

(4) An electric utility is not required to shut off service under this section to an eligible customer for nonpayment to an alternative electric supplier.

(5) The commission shall establish an educational program to ensure that eligible customers are informed of the requirements and benefits of this section.

(6) As used in this section:

(a) “Eligible customer” means either an eligible low-income customer or an eligible senior citizen customer.

(b) “Eligible low-income customer” means a customer whose household income does not exceed 150% of the poverty level, as published by the United States Department of Health and Human Services, or who receives any of the following:

(i) Assistance from a state emergency relief program.

(ii) Food stamps.

(iii) Medicaid.

(c) “Eligible senior citizen customer” means a utility or supplier customer who is 65 years of age or older and who advises the utility of his or her eligibility.

Sec. 10dd. (1) For the fiscal year ending September 30, 2017, there is appropriated to the commission from the assessments imposed under 1972 PA 299, MCL 460.111 to 460.120, the amount of $1,950,000.00 to hire 13 full-time equated positions to implement the provisions of the amendatory act that added section 6t.

(2) For the fiscal year ending September 30, 2017, there is appropriated to the attorney general from the assessments imposed under 1972 PA 299, MCL 460.111 to 460.120, the amount of $150,000.00 to hire 1.0 full-time equated position to implement the provisions of the amendatory act that added section 6t.

(3) For the fiscal year ending September 30, 2017, there is appropriated to the Michigan administrative hearing system from the assessments imposed under 1972 PA 299, MCL 460.111 to 460.120, the amount of $600,000.00 to hire 4.0 full-time equated positions to implement the provisions of the amendatory act that added section 6t.

(4) For the fiscal year ending September 30, 2017, there is appropriated to the department of environmental quality from the assessments imposed under 1972 PA 299, MCL 460.111 to 460.120, the amount of $150,000.00 to hire 1.0 full-time equated position to implement the provisions of the amendatory act that added section 6t.

(5) For the fiscal year ending September 30, 2017, there is appropriated to the Michigan agency for energy from the assessments imposed under 1972 PA 299, MCL 460.111 to 460.120, the amount of $260,000.00 to hire 2.0 full-time equated positions to implement the provisions of the amendatory act that added section 6t.

Sec. 10ee. (1) The commission shall establish a code of conduct that applies to all utilities. The code of conduct shall include, but is not limited to, measures to prevent cross-subsidization, preferential treatment, and, except as otherwise provided under this section, information sharing, between a utility’s regulated electric, steam, or natural gas services and unregulated programs and services, whether those services are provided by the utility or the utility’s affiliated entities. The code of conduct established under this section is also applicable to electric utilities and alternative electric suppliers consistent with sections 10 through 10cc.

(2) A utility may offer its customers value-added programs and services if those programs or services do not harm the public interest by unduly restraining trade or competition in an unregulated market.

(3) Assets of a utility may be used in the operation of an unregulated value-added program or service if the unregulated value-added program or service compensates the utility as provided under this section for the proportional use of the assets of the utility. Except as otherwise provided in subsection (11), assets include the use of the utility’s name and logo.

(4) A utility shall notify the commission of its intent to offer its customers value-added programs and services before offering those programs to its customers.

(5) The commission may initiate informal proceedings to determine if any program or service offered under this section potentially violates subsection (2) or (3). If the commission determines that a potential violation exists, the commission shall conduct formal proceedings to determine whether a violation has occurred and order corrective actions under this act. An informal proceeding allowed under this subsection is not required as a prerequisite to a formal complaint.

(6) A utility offering a value-added program or service under this section shall do all of the following:

(a) Provide the commission with written notice and a description of any newly offered value-added program or service.

(b) Locate within a separate department of the utility or affiliate within the utility’s corporate structure the personnel responsible for the day-to-day management of the program or service.

(c) Maintain separate books and records for the program or service and provide an annual report to the commission showing how all of the utility’s costs associated with the unregulated value-added program or service were allocated to the unregulated program or service. The annual report shall show to what extent the utility’s rates were affected by the allocations. The utility may include this report as part of a request for rate relief.

(7) A utility offering an unregulated value-added program or service under this section shall not promote or market the program or service through the use of utility billing inserts, printed messages on the utility’s billing materials, or other promotional materials included with customers’ utility bills.

(8) All utility costs directly attributable to a value-added program or service allowed under this section shall be allocated to the program or service as required by this section. The direct and indirect costs of all utility assets used in the operation of the program or service shall be allocated to the program or service based on the proportional use by the program or service as compared to the total use of those assets by the utility. The cost of the program or service includes administrative and general expense loading to be determined in the same manner as the utility determines administrative and general expense loading for all of the utility’s regulated and unregulated activities.

(9) A utility may include charges for its value-added programs and services offered under this section on its monthly billings to its customers if the utility complies with all of the following:

(a) The proportional share of all costs associated with the billing process, including the postage, envelopes, paper, and printing expenses, are allocated as required under subsection (8).

(b) A customer’s regulated utility service is not terminated for nonpayment of the value-added program or service portions of the bill.

(c) Unless the customer directs otherwise in writing, a partial payment by a customer is applied first to the bill for regulated service.

(10) In marketing a value-added program or service offered under this section to the public, a utility shall do all of the following:

(a) In the manner and to the extent allowed by commission rule or order, provide upon request to a provider of a similar program or service any lists of customers receiving regulated service that the utility provides to its value-added programs or services. The customer list shall be provided within 5 business days of the request on a nondiscriminatory basis. A new customer shall be added to the customer list within 1 business day of the date the customer requests to enroll in the program or service.

(b) Appropriately allocate utility costs as required under subsection (8) when personnel employed at a utility’s call center provide program marketing information to a prospective customer or customer service support for program payment issues to customers participating in a program or service offered under this section.

(c) Before enrolling a customer into the program or service offered under this section, the utility shall inform the potential customer of all of the following:

(i) That the program or service may be available from another provider.

(ii) That the program or service is not regulated by the commission.

(iii) That a new residential customer has 10 days after enrollment to cancel his or her program or service contract without penalty.

(iv) That the customer’s regulated rates and conditions of service provided by the utility are not affected by enrollment in the program or service or by the decision of the customer to obtain the program or service from another provider.

(d) The utility name and logo may be used to market programs and services offered under this section if the utility complies with both of the following:

(i) Does not market the program or service in conjunction with a regulated service.

(ii) Clearly indicates on all marketing materials that the program or service is not regulated by the commission.

(11) For programs or services directly operated by a utility, costs shall not be allocated to the program or service for the use of the utility’s name or logo.

(12) Except as otherwise provided in this subsection, the commission shall include only the revenues received by a utility to recover costs directly attributable to a value-based program or service under subsection (8) in determining a utility’s base rates. The utility shall file with the commission the percentage of additional revenues over those that are allocated to recover costs directly attributable to a value-added program or service under subsection (8) that the utility wishes to include as an offset to the utility’s base rates. Following a notice and hearing, the commission shall approve or modify the amount to be included as an offset to the utility’s base rates.

(13) Except as otherwise provided in this section, the code of conduct shall not require a utility operating or offering a value-added program or service under this section as part of its regulated service to form a separate affiliate or division, impose further restrictions on the sharing of employees, vehicles, equipment, office space, and other facilities, or require the utility to provide other providers of appliance repair service or value-added programs or services with access to utility employees, vehicles, equipment, office space, or other facilities.

(14) In addition to any penalties allowed under section 10c, for violations of this section a utility shall pay all reasonable costs incurred by the prevailing party.

(15) A utility that offers value-added programs or services under this section shall file an annual report with the commission that provides a list of its offered value-added programs and services, the estimated market share occupied by each value-added program and service offered by the utility, and a detailed accounting of how the costs for the value-added programs and services were apportioned between the utility and the value-added programs and services. The utility shall certify to the commission that it is complying with the requirements of this section. The commission may conduct an audit of the books and records of the utility and the value-added programs and services to ensure compliance with this section.

(16) As used in this section:

(a) “Utility” means an electric, steam, or natural gas utility regulated by the commission.

(b) “Value-added programs and services” means programs and services that are utility or energy related, including, but not limited to, home comfort and protection, appliance service, building energy performance, alternative energy options, or engineering and construction services. Value-added programs and services do not include energy optimization or energy waste reduction programs paid for by utility customers as part of their regulated rates.

Sec. 10ff. (1) Effective January 1, 2017, the energy ombudsman is established in the Michigan agency for energy. The individual serving as energy ombudsman shall meet both of the following requirements:

(a) Understand the rate-making process and instruments to enable the energy ombudsman to provide rate information and track trends related to energy costs for businesses and individuals in this state.

(b) Possess the knowledge necessary to measure historic, ongoing, and future energy costs for businesses and individuals in this state based on the actions of the executive, legislative, and judicial branches of state government.

(2) The energy ombudsman shall do all of the following:

(a) Serve as a liaison for businesses and individuals in the state by guiding energy issues, problems, and disputes from businesses and individuals to the appropriate entity, agency, or venue for resolution.

(b) Monitor the activities of the commission, the Michigan agency for energy, and other regulatory entities of this state whose decisions affect businesses and individuals with respect to energy and communicate those entities’ decisions, policy changes, and developments to businesses and individuals in this state. The issues the energy ombudsman shall monitor include, but are not limited to, all of the following:

(i) Renewable sources of energy.

(ii) Energy efficiency.

(iii) Net metering.

(iv) Combined heat and power.

(v) Distributed generation.

(vi) On-bill financing.

(c) Convene regular meetings in this state to share information and developments pertaining to energy issues, policies, and administrative processes affecting businesses and individuals in this state.

(d) Monitor the implementation of the code of conduct established by the commission under section 10ee and compile and annually publish statistics on unregulated services that are provided by utilities and their affiliates.

Sec. 11. (1) Except as otherwise provided in this subsection, the commission shall ensure the establishment of electric rates equal to the cost of providing service to each customer class. In establishing cost of service rates, the commission shall ensure that each class, or sub-class, is assessed for its fair and equitable use of the electric grid. If the commission determines that the impact of imposing cost of service rates on customers of an electric utility would have a material impact on customer rates, the commission may approve an order that implements those rates over a suitable number of years. The commission shall ensure that the cost of providing service to each customer class is based on the allocation of production-related costs based on using the 75-0-25 method of cost allocation and transmission costs based on using the 100% demand method of cost allocation. The commission may modify this method if it determines that this method of cost allocation does not ensure that rates are equal to the cost of service.

(2) Notwithstanding any other provision of this act, the commission may establish eligible low-income customer or eligible senior citizen customer rates. Upon filing of a rate increase request, a utility shall include proposed eligible low-income customer and eligible senior citizen customer rates and a method to allocate the revenue shortfall attributed to the implementation of those rates upon all customer classes. As used in this subsection, “eligible low-income customer” and “eligible senior citizen customer” mean those terms as defined in section 10t.

(3) Notwithstanding any other provision of this section, the commission shall establish rate schedules that ensure that public and private schools, universities, and community colleges are charged retail electric rates that reflect the actual cost of providing service to those customers. Electric utilities regulated under this section shall file with the commission tariffs to ensure that public and private schools, universities, and community colleges are charged electric rates as provided in this subsection.

Enacting section 1. Sections 6c and 6e of 1939 PA 3, MCL 460.6c and 460.6e, are repealed.

Enacting section 2. This amendatory act takes effect 120 days after the date it is enacted into law.

Enacting section 3. This amendatory act does not take effect unless Senate Bill No. 438 of the 98th Legislature is enacted into law.

Secretary of the Senate

Clerk of the House of Representatives

Approved

Governor