ELECTRIC GENERATION S.B. 213 & S.B. 1048, & H.B. 5524:
SUMMARY AS ENACTED
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Senate Bill 213 (as enacted) PUBLIC ACT 295 of 2008
Senate Bill 1048 (as enacted) PUBLIC ACT 287 of 2008
House Bill 5524 (as enacted) PUBLIC ACT 286 of 2008
Sponsor: Senator Patricia L. Birkholz (S.B. 213 & 1048)
Representative Frank Accavitti (H.B. 5524)
Senate Committee: Energy Policy and Public Utilities
House Committee: Energy and Technology
Date Completed: 1-7-09
CONTENT
Senate Bill 213 created the "Clean, Renewable, and Efficient Energy Act" to establish a renewable energy standard, consisting of a renewable energy capacity portfolio and a renewable energy credit portfolio, under which 10% of an electric provider's energy must come from renewable sources by 2015; require electric and natural gas providers to file energy optimization plans; require the Public Service Commission (PSC) and the Department of Management and Budget (DMB) to take certain actions related to energy efficiency and conservation; and provide for the establishment of wind energy resource zones.
Regarding the renewable energy standard, the bill does the following:
-- Requires a provider to meet the renewable energy credit standard by specific means, including the generation of electricity from renewable energy systems, the purchase of renewable energy credits, or, if approved by the PSC, the substitution of energy optimization credits and advanced cleaner energy credits for renewable energy credits.
-- Authorizes the PSC to grant up to two extensions of the 2015 renewable energy standard's deadline for good cause.
-- Requires an electric provider to file with the PSC a renewable energy plan to meet the standard.
-- Requires the plan of a provider whose rates are regulated by the PSC to establish a revenue recovery mechanism for the incremental costs of compliance within the provider's customer rates.
-- Prescribes maximum retail rate impacts resulting from compliance with the renewable energy standard.
-- Allows renewable energy credits to be traded, sold, or transferred.
-- Establishes conditions under which a utility with at least 1.0 million customers must obtain renewable energy credits.
-- Establishes qualifying criteria for a renewable energy credit.
-- Creates additional Michigan incentive renewable energy credits for meeting certain criteria, including the use of Michigan-made equipment and a Michigan workforce.
-- Requires a regulated provider to recover all of its incremental costs of compliance and all reasonable and ongoing costs of compliance through its retail electric rates, subject to the retail rate impact limits.
-- Requires the PSC to conduct an annual renewable cost reconciliation for a regulated provider and adjust the revenue recovery mechanism, if necessary, to ensure the provider's recovery of its incremental cost of
compliance with the renewable energy standard.
-- Requires a regulated provider that fails to meet the standard's deadline to purchase renewable energy credits to meet the standard.
-- Allows the Attorney General or a customer of a member-regulated cooperative electric utility to bring a civil action against the utility if it fails to meet the Act's requirements.
-- Allows the PSC to conduct a contested case to review allegations that an alternative electric supplier has violated the Act, and prescribe sanctions.
-- Establishes provider and PSC reporting requirements, including a requirement that the PSC report to the Legislature on the potential impact of decoupling regulated rates.
House Bill 5524 amended Public Act 3 of 1939, the Public Service Commission law, to do the following:
-- Revise procedures for the filing, investigation, and hearing of petitions and applications for gas and electric utility rate increases.
-- Increase the time period the PSC has to make a determination in a rate filing, and provide that a petition or application is considered approved if the PSC does not make a determination by that deadline.
-- Require the PSC, upon a gas utility's request, to establish load retention transportation rate schedules or approve gas transportation contracts for the purpose of retaining large industrial or commercial customers.
-- Require the PSC to adopt standard rate application filing forms and instructions.
-- Require a merchant plant that generated electricity from wood or solid wood waste pursuant to a contract of at least 20 years before January 1, 2008, to recover costs exceeding the amount the plant is paid under the contract, up to $1.0 million per month.
-- Prohibit a person from acquiring, controlling, or merging with a jurisdictional regulated utility without PSC approval; and prescribe approval application procedures.
-- Allow an electric utility that proposes to construct, invest in, or purchase generation facilities or enter into a power purchase agreement for at least six years, to apply for a certificate of necessity from the PSC, if the construction, investment, or purchase costs at least $500.0 million.
-- Authorize the PSC to implement separate review criteria and approval standards for utilities with fewer than 1.0 million customers, for projects that cost less than $500.0 million.
-- Require the PSC to establish standards for an integrated resource plan that a utility requesting a certificate must file.
The bill also requires the PSC to phase in electric rates for utilities with more than 1.0 million Michigan customers equal to the cost of providing service to each customer class, subject to certain conditions; and requires the PSC to approve rates for smaller utilities equal to the cost of providing service.
Additionally, the bill amended the part of the PSC law known as the "Customer Choice and Electricity Reliability Act" to do the following:
-- Require the PSC to issue orders providing that up to 10% of an electric utility's average retail sales may take service from an alternative electric supplier (AES) at any time.
-- Allow an AES customer to receive standard tariff service from an electric utility in accordance with its procedures in place on January 1, 2008, for the return of an AES customer to utility service; and allow the PSC to amend the procedures as needed.
-- Require the PSC to authorize rates that will ensure that an electric utility that offered retail open access service from 2002 until the bill's effective date fully recovers within five years its restructuring costs and any associated accrued regulatory costs.
-- Require the PSC to adopt service quality and reliability standards for generation systems.
-- Require the PSC to submit to the Legislature and the Governor reports on electricity quality and efficiency, the possibility of separating generation and distribution, and the potential benefit of creating an electric generation purchasing pool.
-- Require the PSC to review its existing rules and amend them, if necessary, to implement performance standards for generation and distribution facilities.
-- Require each regulated utility to file with the PSC a plan for using dispatchable customer-owned distributed generation within the context of its integrated planning resource process.
-- Revise provisions pertaining to the ability of municipally owned utility customers to choose service from an AES.
-- Appropriate to the PSC $2.5 million to hire 25.0 full-time equated employees.
-- Delete a sunset on provisions specifying the purposes of the Act.
-- Delete provisions requiring the PSC to conduct an annual true-up adjustment for each utility to ensure the recovery of stranded costs.
-- Delete provisions that required a 5% reduction in residential rates and the capping of rates for a period of time, as well as the use of securitization savings for implementation of the 5% reduction and deposit into the Low Income and Energy Efficiency Fund.
Senate Bill 1048 amended the Income Tax Act to establish an income tax credit for the purchase and installation of certain products that meet Energy Star energy efficiency guidelines and for utility charges imposed to meet the renewable energy standard of Senate Bill 213, subject to certain conditions.
Senate Bills 213 and 1048 were tie-barred to House Bill 5524 and to each other. House Bill 5524 was tie-barred to Senate Bill 213. The bills took effect on October 6, 2008. They are described below in further detail.
Senate Bill 213
Part 1: General Provisions
The Act states that its purpose "is to promote the development of clean energy, renewable energy, and energy optimization through the implementation of a clean, renewable, and energy efficient standard that will cost effectively do all of the following:
(a) Diversify the resources used to reliably meet the energy needs of consumers in the state.
(b) Provide greater energy security through the use of indigenous energy resources available within the state.
(c) Encourage private investment in renewable energy and energy efficiency.
(d) Provide improved air quality and other benefits to energy consumers and citizens of the state."
Part 1 also defines terms used in the Act. "Electric provider" means any of the following, as applicable:
-- Any person or entity that is regulated by the PSC for the purpose of selling electricity to retail customers in Michigan.
-- A municipally owned electric utility in Michigan.
-- A cooperative electric utility in Michigan.
-- Except as used in provisions pertaining to energy optimization, an alternative electric supplier licensed in Michigan.
Other definitions are noted below.
Part 2: Energy Standards
Subpart A: Renewable Energy
PSC-Regulated Providers. These provisions apply only to electric providers whose rates are regulated by the PSC.
Within 90 days after the PSC issues a temporary order to implement the Act, each electric provider must file with the Commission a proposed renewable energy plan. The plan must do all of the following:
-- Describe how the provider will meet the renewable energy standard.
-- Include the expected incremental cost of compliance with the standard for a 20-year period beginning when the plan is approved by the PSC.
-- Specify whether the number of megawatt hours of electricity used in the calculation of the renewable energy credit portfolio will be weather-normalized or based on the average number of megawatt hours of electricity the provider sold annually during the previous three years to Michigan retail customers.
Once the plan is approved, the option for calculating the portfolio may not be changed. ("Renewable energy credit portfolio" means the sum of the renewable energy credits a provider achieves for a particular year.)
For a provider with more than 1.0 million Michigan retail customers as of January 1, 2008, the plan also must describe the bidding process the provider will use to obtain renewable energy credits. The description must include measures to be employed in the preparation of requests for proposals (RFPs) received to ensure that any bidder that is an affiliate of the electric utility is not given a competitive advantage over any other bidder and that each bidder, including an affiliate of the provider, is treated in a fair and nondiscriminatory manner.
The proposed plan must establish a nonvolumetric mechanism for the recovery of the incremental costs of compliance within the provider's customer rates. ("Incremental costs of compliance" means the net revenue required by a provider to comply with the renewable energy standard, calculated as provided in the Act.) The revenue recovery mechanism may not result in rate impacts that exceed the monthly maximum retail rate impacts specified in the Act. A revenue recovery mechanism is subject to adjustment under Sections 47(4) and 49. (Section 47(4) requires the PSC to hold a contested case hearing if a provider's incremental costs of compliance exceed the revenue recovery mechanism and the balance of accumulated reserve funds. Section 49 requires the PSC to commence an annual renewable cost reconciliation for a regulated provider.)
A customer participating in a PSC-approved voluntary renewable energy program under an agreement in effect on the Act's effective date may not incur charges under the mechanism unless they exceed the charges the customer is incurring for the voluntary program. In that case, the customer will incur only the difference between the charge assessed under the revenue recovery mechanism and the charges the customer is incurring for the voluntary program. The limitation on charges applies only during the term of the agreement, not including automatic agreement renewals, or until one year after the Act's effective date, whichever is later. Before entering into an agreement with a customer to participate in a PSC-approved voluntary renewable energy program and before the last automatic monthly renewal of such an agreement that will occur less than one year after the Act's effective date, a provider must notify the customer that the customer will be responsible for the full applicable charges under the revenue recovery mechanism as well as under the voluntary program as provided in the Act.
If proposed by a provider in its plan, the revenue recovery mechanism must result in an accumulation of reserve funds in advance of expenditure and the creation of a regulatory liability that accrues interest at the average short-term borrowing rate available to the provider during the appropriate period. If proposed by the provider in its plan, the PSC must establish a minimum balance of accumulated reserve funds for the purposes of Section 47(4).
The PSC must conduct a contested case hearing on the proposed plan pursuant to the Administrative Procedures Act (APA).
If a renewable energy generator files a petition to intervene in the contested case in the manner prescribed by the Commission's rules for interventions generally, the PSC must grant the petition. After the hearing and within 90 days after the proposed plan is filed with the PSC, the Commission must approve the plan, with any changes the provider consents to, or reject it.
The PSC may not approve a provider's plan unless it determines both that the plan is reasonable and prudent, and that the life-cycle cost of renewable energy acquired or generated under the plan less the projected life-cycle net savings associated with the provider's energy optimization plan does not exceed the expected life-cycle cost of electricity generated by a new conventional coal-fired facility.
In determining whether the plan is reasonable and prudent, the PSC must take into consideration the projected costs and whether projected costs included in previous plans were exceeded. In determining the expected life-cycle cost of electricity generated by a new conventional coal-fired facility, the PSC must consider data from Michigan and the states of Illinois, Indiana, Minnesota, Ohio, and Wisconsin, including, if applicable, the life-cycle costs of the renewable energy system and new conventional coal-fired facilities. When determining the life-cycle costs of the renewable energy system and new conventional coal-fired facilities, the PSC must use a methodology that includes consideration of the value of energy, capacity, and ancillary services. The Commission also must consider other costs, such as transmission, economic benefits, and environmental costs, including greenhouse gas constraints or taxes. In performing its assessment, the PSC may use other available data, including national or regional reports and data published by State or Federal government agencies, industry associations, and consumer groups.
A provider may not begin recovery of the incremental costs of compliance within its rates until the PSC has approved its plan.
Every two years after initial approval, the PSC must conduct a contested case hearing on a plan. The annual renewable cost reconciliation under Section 49 for that year may be joined with the overall plan review in the same hearing. After the hearing, the PSC must approve the plan with any changes to which the provider consents, or reject the plan and any proposed amendments to it.
If a provider proposes to amend its plan at a time other than during the biennial review process, it must file the proposed amendment with the PSC. If the proposed amendment would modify the revenue recovery mechanism, the PSC must conduct a contested case hearing. The annual renewable cost reconciliation may be joined with the plan amendment in the same contested case proceeding. After the hearing and within 90 days after the amendment is filed, the PSC must approve the amendment, with any changes to which the provider consents, or reject the plan and any proposed amendments to it.
If the PSC rejects a proposed plan or amendment, it must explain in writing the reasons for its determination.
The Act defines "renewable energy" as electricity generated using a renewable energy system, i.e., a facility, electricity generation system, or integrated set of electricity generation systems that uses one or more renewable energy resources to generate electricity. "Renewable energy system" does not include a hydroelectric facility that uses a dam constructed after the Act's effective date, unless the dam is a repair or replacement of a dam in existence on that date or an upgrade of a dam in existence on that date that increases its energy efficiency. The term also does not include an incinerator, unless it is a municipal solid waste incinerator and was brought into service before the Act's effective date, including any of the following: 1) any upgrade that increases energy efficiency, 2) any expansion before the Act's effective date, or 3) any expansion of an incinerator on or before the Act's effective date to an approximate design rated capacity of not more than 950 tons per day pursuant to the terms of a final RFP requested by October 1, 1986.
"Renewable energy resource" means a resource that replenishes naturally over a human, not geological, time frame and that is derived ultimately from solar power, water power, or wind power. A renewable energy resource comes from the sun or from thermal inertia of the earth and minimizes the output of toxic material in the conversion of the energy. The term does not include petroleum, nuclear, natural gas, or coal. The term does include the following:
-- Biomass.
-- Solar and thermal energy.
-- Wind energy.
-- Kinetic energy of moving water, including waves, tides, or currents; and water released through a dam
-- Geothermal energy.
-- Municipal solid waste.
-- Landfill gas produced by municipal solid waste.
"Biomass" means any organic matter that is not derived from fossil fuels, that can be converted to usable fuel for the production of energy, and that replenishes over a human, not geological, time frame, including all of the following:
-- Agricultural crops and crop waste.
-- Short-rotation energy crops.
-- Herbaceous plants.
-- Trees and wood, but only if derived from sustainably managed forests or procurement systems.
-- Precommercial wood-thinning waste, brush, or yard waste.
-- Wood waste and residue from the processing of wood products or paper.
-- Animal waste.
-- Aquatic plants.
-- Food production and processing waste.
-- Organic byproducts from the production of biofuels.
Cooperatives & AESs. These provisions apply only to AESs and cooperative electric utilities that have elected to become member-regulated under the Electric Cooperative Member-Regulation Act.
Each AES or cooperative electric utility must file with the PSC a proposed renewable energy plan within 90 days or 120 days, respectively, after the Commission issues its temporary order implementing the Act. The plan must describe how the provider will meet the renewable energy standard, and specify whether the number of megawatt hours used in calculating the renewable energy portfolio will be weather-normalized or based on the average number of megawatt hours of electricity the provider sold annually during the previous three years to Michigan retail customers. Once the plan is approved, the option for the calculation may not be changed.
The PSC must provide an opportunity for public comment on the proposed plan. After the opportunity for public comment and within 90 days after the plan is filed, the PSC must approve the plan, with any changes to which the provider consents, or reject it.
Every two years after initial approval of a plan, the PSC must review it. The Commission must provide an opportunity for public comment. After the public comment opportunity and within 90 days after the amendment is filed, the PSC must approve, with any changes to which the provider consents, or reject any proposed amendments.
If the provider proposes to amend its plan at a time other than during the biennial review process, it must file the proposed amendment with the PSC. The Commission must provide an opportunity for public comment. After the public comment opportunity and within 90 days after the amendment is filed, the PSC must approve it, with any changes to which the provider consents, or reject the amendment.
If the PSC rejects a proposed plan or amendment, it must explain in writing the reasons for its determination.
Municipally Owned Electric Utilities. These provisions apply only to municipally owned electric utilities.
Each provider must file a proposed renewable energy plan with the PSC within 120 days after the Commission issues its temporary order. Two or more providers that each serve fewer than 15,000 customers may file jointly. The proposed plan must do all of the following:
-- Describe how the provider will meet the renewable energy standard.
-- Include the expected incremental cost of compliance with the standard.
-- Describe the manner in which the provider will allocate costs.
-- Specify whether the number of megawatt hours used in the calculation of the renewable energy credit portfolio will be weather-normalized or based on the average number of megawatt hours the provider sold annually during the previous three years to Michigan retail customers.
The option for calculating the portfolio may not be changed once the PSC determines that the proposed plan complies with the Act.
Except as otherwise provided, the PSC must provide an opportunity for public comment on the proposed plan. After the applicable opportunity and within 90 days after the plan is filed, the Commission must determine whether it complies with the Act.
Every two years after the initial determination, the PSC must review the plan. Except as otherwise provided, the PSC must provide an opportunity for public comment. After the applicable opportunity, the PSC must determine whether any proposed amendment complies with the Act. The proposed amendment is adopted if the PSC determines that it complies.
If a provider proposes to amend its renewable energy plan at a time other than during the biennial review process, the provider must file the proposed amendment with the PSC. The Commission must provide an opportunity for public comment. After the applicable opportunity and within 90 days after the amendment is filed, the PSC must determine whether it complies with the Act. The proposed amendment is adopted if the PSC determines that it complies.
The PSC is not required to provide any public comment opportunity if the provider's governing body already has provided one and filed the comments with the Commission.
If the PSC determines that a proposed plan or amendment does not comply with the Act, it must explain in writing the reasons for its determination.
Renewable Energy Capacity Portfolio. Subject to the Act's provisions regarding deadline extensions and recovery of the incremental cost of compliance, in addition to requirements pertaining to a renewable energy credit portfolio, an electric provider that is an electric utility with at least 1.0 million Michigan retail customers as of January 1, 2008, must achieve a renewable energy capacity portfolio of not less than the following:
-- For an electric provider with more than 1.0 million but fewer than 2.0 million Michigan retail electric customers on January 1, 2008, 200 megawatts by December 31, 2013, and 500 megawatts by December 31, 2015.
-- For an electric provider with more than 2.0 million Michigan retail customers on January 1, 2008, 300 megawatts by December 31, 2013, and 600 megawatts by December 31, 2015.
A provider's renewable energy capacity portfolio must be calculated by adding the following:
-- The nameplate capacity in megawatts of renewable energy systems owned by the provider that were not in commercial operation before the Act's effective date.
-- The capacity in megawatts of renewable energy that the provider is entitled to purchase under contracts that were not in effect before the Act's effective date.
Renewable Energy Credit Portfolio. Subject to the provisions regarding deadline extensions and recovery of the incremental cost of compliance, a provider must achieve a renewable energy credit portfolio in 2012, 2013, 2014, and 2015 based on the sum of the following:
-- The number of renewable energy credits from electricity generated in the one-year period preceding the Act's effective date that would have been transferred to the electric provider pursuant to the Act, if it had been in effect during that period.
-- The number of renewable energy credits equal to the number of megawatt hours of electricity produced or obtained by the provider in the one-year period preceding the Act's effective date from renewable energy systems for which recovery in electric rates was approved on that date.
-- Renewable energy credits in an amount calculated as follows: taking into account the number of renewable energy credits under the first two calculations, determine the number of additional renewable energy credits that the provider would need to reach a 10% renewable energy portfolio in that year; and multiply that number by 20% for 2012, 33% for 2013, 50% for 2014, and 100% for 2015.
In 2016 and each following year, a provider must maintain a renewable energy credit portfolio that consists of at least the same number of renewable energy credits as were required in 2015.
A provider's renewable energy credit portfolio must be calculated by determining the number of renewable energy credits used to comply with Subpart A during the applicable year and dividing by one of the following at the option of the provider as specified in its renewable energy plan:
-- The number of weather-normalized megawatt hours of electricity the provider sold during the previous year to Michigan retail customers.
-- The average number of megawatt hours of electricity the provider sold annually during the previous three years to Michigan retail customers.
The quotient must be multiplied by 100.
Subject to provisions regarding substitution, each provider must meet the renewable energy credit standard with renewable energy credits obtained by one or more of the following means:
-- Generating electricity from renewable energy systems for sale to retail customers.
-- Purchasing or otherwise acquiring renewable energy credits with or without the associated renewable energy.
An electric provider may substitute energy optimization credits and/or advanced cleaner energy credits with or without the associated advanced cleaner energy, for renewable energy credits otherwise required to meet the renewable energy credit standard if the substitution is approved by the PSC. Commission approval is not required, however, to substitute advanced cleaner energy from industrial cogeneration for renewable energy credits. The PSC may not approve a substitution unless it determines that that substitution is cost-effective compared to other sources of renewable energy credits and, if the substitution involves advanced cleaner energy credits, that the advanced cleaner energy system provides carbon dioxide emissions benefits. In determining whether the substitution of advanced cleaner energy credits is cost-effective, the PSC must include as part of the costs of the system the environmental costs attributed to the advanced cleaner energy system including the costs of environmental control equipment or greenhouse gas constraints or taxes. The PSC's determinations must be made after a contested case hearing that includes consultation with the Department of Environmental Quality on the issue of carbon dioxide emissions benefits, if relevant, and environmental costs.
A provider may not use energy optimization credits and/or advanced cleaner energy credits to meet more than 10% of the renewable energy credit standard. A provider may not use advanced cleaner energy from advanced cleaner energy systems in existence on January 1, 2008, to meet more than 70% of this 10% limit. The 10% limit does not apply to advanced cleaner energy credits from plasma arc gasification.
Substitutions must be made at the following rates per renewable energy credit:
-- One energy optimization credit.
-- One advanced cleaner energy credit from plasma arc gasification or industrial cogeneration.
-- Ten advanced cleaner energy credits from other sources.
"Energy optimization credit" means a credit certified pursuant to the Act that represents achieved energy optimization. "Energy optimization" means energy efficiency; load management, to the extent that it reduces overall energy use; and energy conservation, but only to the extent that the decreases it produces in electricity consumption are measured objectively and attributable to an energy optimization plan (described below). "Energy efficiency" means a decrease in customer consumption of electricity or natural gas achieved through measures or programs that target customer behavior, equipment, devices, or materials without reducing the quality of energy services. "Load management" means measures or programs that target equipment or devices to result in decreased peak electricity demand, such as by shifting demand from a peak to an off-peak period.
"Advanced cleaner energy credit" means a credit certified under the Act that represents electricity generated using an advanced cleaner energy system. "Advanced cleaner energy" means electricity generated using an "advanced cleaner energy system", i.e., a gasification facility, an industrial cogeneration facility, a coal-fired electric generating facility if at least 85% of the carbon dioxide emissions are captured and permanently geologically sequestered, or an electric generating facility or system that uses technologies not in commercial operation on the Act's effective date.
"Gasification facility" means a facility located in Michigan that uses a thermochemical process that does not involve direct combustion to produce synthesis gas, composed of carbon monoxide and hydrogen, from carbon-based feedstocks (such as coal; petroleum coke; wood; biomass; hazardous waste; medical waste; industrial waste; and solid waste, including municipal solid waste, electronic waste, and waste described in Section 11514 of the Natural Resources and Environmental Protection Act (NREPA) and that uses the synthesis gas or a mixture of the synthesis gas and methane to generate electricity for commercial use. The term includes the transmission lines, gas transportation lines and facilities, and associated property and equipment attributable specifically to the facility. The term also includes an integrated gasification combined cycle facility and a plasma arc gasification facility.
(Section 11514 of NREPA refers to medical waste, used beverage containers, whole motor vehicle tires, yard clippings, used oil, lead acid batteries, low-level radioactive waste, regulated hazardous waste, bulk or noncontainerized liquid waste or waste containing free liquids, PCBs, and asbestos waste.)
"Industrial cogeneration facility" means a facility that generates electricity using industrial thermal energy or industrial waste energy.
"Industrial thermal energy" means thermal energy that is a by-product of an industrial or manufacturing process that would otherwise be wasted. "Industrial waste energy" means exhaust gas or flue gas that is a by-product of an industrial or manufacturing process that would otherwise be wasted. For the purposes of these definitions, industrial or manufacturing process does not include the generation of electricity.
Location or Source of System or Energy. A renewable energy system that is the source of renewable energy credits used to satisfy the renewable energy standard (i.e., the minimum renewable energy capacity portfolio, if applicable, and the required renewable energy portfolio) must be either located outside of Michigan in the retail electric customer service territory of any provider that is not an AES, or located anywhere in this State. For the purposes of this provision, a retail electric customer service territory is considered to be the territory recognized by the PSC on January 1, 2008, and any expansion recognized by the PSC after that date under the PSC law. The PSC also may expand a service territory for the purposes of this provision if a lack of transmission lines limits the ability to obtain sufficient renewable energy from renewable energy systems that meet the location requirements.
The renewable energy system location requirements do not apply if one or more of the following requirements are met:
-- The renewable energy system is a wind energy conversion system that was under construction or operational and owned by a provider on January 1, 2008 (unless the provider is an AES).
-- The renewable energy system is a wind energy conversion system that includes multiple wind turbines, at least one of the wind turbines meets the location requirements, and the remaining turbines are within 15 miles of a wind turbine that is part of the conversion system and that meets the requirements.
-- Before January 1, 2008, a provider serving a maximum of 75,000 retail electric customers in Michigan filed an application for a certificate of authority for the renewable energy system with a state regulatory commission in another state that also is served by that provider.
-- Electricity generated from the renewable energy system is sold by a not-for-profit entity located in Indiana or Wisconsin to a municipally owned or cooperative electric utility in Michigan under a contract in effect on January 1, 2008, and the electricity is not being used to meet another state's renewable portfolio standard.
-- Electricity generated from the renewable energy system is sold by a not-for-profit entity located in Ohio to a municipally owned electric utility in Michigan under a contract approved by resolution of the utility's governing body by January 1, 2008, and the electricity is not being used to meet another state's renewable portfolio standard.
The location requirements also do not apply if the renewable energy system is a wind energy conversion system and the electricity generated from the system, or the renewable energy credits associated with that electricity, are being purchased under a contract in effect on January 1, 2008. If a provider uses that electricity or those credits to meet portfolio requirements established after January 1, 2008, by the legislature of the state in which the system is located, the provider, for the purpose of meeting the Act's renewable energy credit standard, may obtain, by any means authorized in the Act, up to the same number of replacement credits from any other wind energy conversion system located in that state. These provisions may not be used by an AES unless it was licensed in Michigan on January 1, 2008. Renewable energy credits from a renewable energy system under a contract with an AES under these provisions may not be used by another provider to meet its requirements under Part 2.
With regard to a provider serving a maximum of 75,000 Michigan retail customers, or in the case of electricity sold by a not-for-profit entity in Ohio to a municipally owned utility, renewable energy credits may not be granted for electricity generated using more than 10.0 megawatts or 13.4 megawatts, respectively, of nameplate capacity of the renewable energy system.
Also, the location requirements do not apply if all of the following requirements are met:
-- The renewable energy system is a wind energy system, is interconnected to the provider's transmission system, and is located in a state in which the provider has service territory.
-- The provider competitively bid any contract for engineering, procurement, or construction of the renewable energy system, if the provider owns the system, or for the purchase of renewable energy and associated renewable energy credits from the system, if the provider does not own the system, in a process open to renewable energy systems sited in Michigan.
-- The renewable energy credits from the system are only used by that provider to meet the renewable energy standard.
-- The provider is not an AES.
Advanced cleaner energy systems that are the source of advanced cleaner energy credits must either be located outside this State in the service territory of any electric provider that is not an AES, or located anywhere in Michigan.
Extensions. Upon petition by a provider, for good cause the PSC may grant two extensions of the 2015 renewable energy standard deadline. Each extension may be for up to one year.
If two extensions have been granted, upon subsequent petition by the provider at least three months before the second deadline expires, the PSC, after consideration of previous extension requests and for good cause, must establish a revised renewable energy standard attainable by the provider. If the provider achieves the revised standard, it is considered to be in compliance with Subpart A.
An electric provider that makes a good faith effort to spend the full amount of incremental costs of compliance as outlined in its approved renewable energy plan and that complies with its approved plan, subject to any approved extensions or revisions, is considered to be in compliance with Subpart A.
Good cause includes the provider's inability, as determined by the PSC, to meet the standard because of a renewable energy system feasibility limitation, including any of the following:
-- Renewable energy system site requirements, zoning, siting, land use issues, permits (including environmental permits), any proposed certificate of need process under the PSC law, or any other necessary governmental approvals that effectively limit availability of renewable energy systems, if the provider exercises reasonable diligence in attempting to secure the necessary governmental approvals.
-- Equipment cost or availability issues, including electrical equipment or renewable energy system component shortages or high costs that effectively limit availability of renewable energy systems.
-- Cost, availability, or time requirements for electric transmission and interconnection.
-- Projected or actual unfavorable electric system reliability or operational impacts.
-- Labor shortages that effectively limit availability of renewable energy systems.
-- A court order that effectively limits the availability of renewable energy systems.
("Reasonable diligence" includes submitting timely applications for the necessary governmental approvals and making good faith efforts to ensure that the applications are administratively complete and technically sufficient.)
Utilities with at least 1.0 Million Customers. Subject to specified exceptions and requirements, a provider with at least 1.0 million retail customers in Michigan as of January 1, 2008, must obtain the renewable energy credits that are necessary to meet the renewable energy credit standard in 2015 and thereafter as discussed below.
At the provider's option, a maximum of 50% of the credits may be from any of the following: renewable energy systems that are developed and owned by the provider, and renewable energy systems that are developed by one or more third parties pursuant to a contract with the provider under which the ownership of the system may be transferred to the provider, but not before the system begins commercial operation. The contract must be executed after a competitive bidding process conducted pursuant to guidelines established by the PSC. An affiliate of the provider may submit a proposal in response to an RFP, subject to the code of conduct under the PSC law, and the sanctions for a violation of the code of conduct.
(The code of conduct includes measures to prevent cross-subsidization, information sharing, and preferential treatment, between a utility's regulated and unregulated services, whether those services are provided by the utility or its affiliated entities.)
The provider must bid competitively any contract for engineering, procurement, or construction of any new systems. A provider may, however, consider unsolicited proposals presented to it by a renewable energy system developer outside of a competitive bid process. If the provider determines that such a proposal provides opportunities that may not otherwise be available or commercially practical, it may enter into a contract with the developer.
At least 50% of the credits must be from renewable energy contracts that do not require transfer of ownership of the applicable renewable energy system to the provider or from contracts for the purchase of renewable energy credits without the associated renewable energy. A renewable energy contract or contract for the purchase of renewable energy credits also must be executed after a competitive bidding process conducted according to PSC guidelines. A provider may, however, consider unsolicited proposals presented to it outside of a competitive bid process by a renewable energy system developer that is not affiliated with the provider. If the provider determines that such a proposal provides opportunities that may not otherwise be available or commercially practical, the provider may enter into a contract with the developer. The contract is subject to review and approval by the PSC in the same manner as the proposed renewable energy plan. A provider or its affiliate may not submit a proposal in response to its own RFPs under these provisions. If a provider selects a bid other than the least price conforming bid from a qualified bidder, the provider promptly must notify the PSC. The Commission must determine in the manner provided in the Act whether the provider had good cause for selecting that bid. If the PSC determines that the provider did not have good cause, it must disapprove the contract.
These provisions do not apply to renewable energy credits that are transferred to the provider pursuant to the Act. These provisions also do not apply to renewable energy credits that are produced or obtained by the provider from renewable energy systems for which recovery in electric rates was approved as of the Act's effective date, including credits resulting from biomass co-firing of electric generation facilities in existence on that date, except to the extent the number of megawatt hours generated annually by that method exceeds the number of megawatt hours generated during the one-year period immediately before the Act's effective date.
A provider must submit a contract for renewable energy credits to the PSC for review and approval. If the PSC approves the contract, it is considered consistent with the provider's renewable energy plan. The PSC may not approve a contract based on an unsolicited proposal unless it determines that the proposal provides opportunities that may not otherwise be available or commercially practical.
Ownership of Credits. If a provider obtains renewable energy for resale to retail or wholesale customers under an agreement under the Federal Public Utility Regulatory Policies Act (PURPA), ownership of the associated renewable energy credits must be as provided by the PURPA agreement. If the agreement does not provide for ownership of the credits, the following apply:
-- Except to the extent that a separate agreement governs, for the duration of the PURPA agreement, for every five credits associated with renewable energy, ownership of four of the credits is transferred to the provider with the renewable energy, and ownership of one credit remains with the qualifying small power production facility.
-- If a separate agreement in effect on January 1, 2008, provides for the ownership of the renewable attributes of the generated electricity, the separate agreement governs until January 1, 2013, or until it expires, whichever occurs first.
("Qualifying small power production facility" means that term as defined in 16 USC 824a-3, i.e., a small power production facility (a facility that is an eligible solar, wind, waste, or geothermal facility that produces electric energy solely by the use, as a primary energy source, of biomass, waste, renewable resources, geothermal resources, or any combination of those sources; and has a maximum power production capacity of 80 megawatts) that the Federal Energy Regulatory Commission (FERC) determines meets its requirements.)
If an investor-owned electric utility with fewer than 20,000 customers, a municipally owned electric utility, or a cooperative electric utility obtains all or substantially all of its electricity for resale under a power purchase agreement or agreements in existence on the Act's effective date, ownership of any associated renewable energy credits is considered to be transferred to the provider purchasing the electricity. The number of credits associated with the purchased electricity must be determined by multiplying the total number of renewable energy credits associated with the total power supply of the seller during the term of the agreement by a fraction, the numerator of which is the amount of energy purchased under the agreement or agreements and the denominator of which is the total power supply of the seller during the term of the agreement. This provision does not apply unless the seller and the provider purchasing the electricity agree that it applies, and/or, for a seller that is an independent investor-owned electric utility whose retail electric rates are regulated by the PSC, the Commission reduces the number of credits required under the renewable energy credit standard for the seller by the number of credits to be transferred to the provider purchasing the electricity.
Contract Terms. If, after the Act's effective date, a provider whose rates are regulated by the PSC (a rate-regulated provider) enters into a renewable energy contract or a contract to purchase renewable energy credits without the associated renewable energy, the PSC must determine whether the contract provides reasonable and prudent terms and conditions and complies with the retail rate impact limits prescribed in the Act. In making this determination, the PSC must consider the contract price and term. If the contract is a renewable energy contract, the PSC also must consider at least all of the following:
-- The cost to the provider and its customers of the impacts of accounting treatment of debt and associated equity requirements imputed by credit rating agencies and lenders attributable to the renewable energy contract.
-- Subject to the Act's incremental compliance cost recovery provisions, the life-cycle cost of the contract to the provider and customers, including costs, after expiration of the contract, of maintaining the same renewable energy output in megawatt hours, whether by purchases from the marketplace, by extension or renewal of the contract, or by the provider's purchasing the renewable energy system and continuing its operation.
-- Provider and customer price and cost risks if the renewable energy systems supporting the contract move from contracted pricing to market-based pricing after the contract's expiration.
With regard to the cost of the impacts of accounting treatment of debt and associated equity requirements, the PSC must use standard rating agency, lender, and accounting practices for electric utilities in determining these costs, unless the impacts for the provider are known.
Granting of Credits; Incentive Credits. Except as otherwise provided, one credit must be granted to the owner of a renewable energy system for each megawatt hour of electricity generated from the system, subject to the three conditions described below:
First, if a system uses both a renewable energy resource and a nonrenewable energy resource to generate electricity, the number of renewable energy credits must be based on the percentage of the electricity generated from the renewable resource.
Second, credits may not be granted for renewable energy generated from a municipal solid waste incinerator to the extent that the energy was generated by operation of the incinerator in excess of the greater of the following, as applicable: its nameplate capacity rating effective on January 1, 2008; or, if the incinerator is expanded after the Act's effective date to an approximate continuous design rated capacity of not more than 950 tons per day pursuant to the terms of a final RFP issued by October 1986, the nameplate capacity rating required to accommodate the expansion.
Third, credits may not be granted for renewable energy whose renewable attributes are used by a provider in a PSC-approved voluntary renewable energy program.
Subject to those conditions, the following additional renewable energy credits, to be known as Michigan incentive renewable energy credits, must be granted under the following circumstances:
-- Two credits for each megawatt hour of electricity from solar power.
-- One-fifth of a credit for each megawatt hour of electricity generated from a renewable energy system, other than wind, at peak demand time as determined by the PSC.
-- One-fifth of a credit for each megawatt hour of electricity generated from a renewable energy system during off-peak hours, stored using advanced electric storage technology or a hydroelectric pumped storage facility, and used during peak hours.
-- One-tenth of a credit for each megawatt hour generated from a renewable energy system constructed using equipment made in Michigan as determined by the PSC.
-- One-tenth of a credit for each megawatt hour from a renewable energy system constructed using a workforce composed of Michigan residents as determined by the PSC.
With regard to the credits for electricity generated during off-peak hours, stored, and used during peak hours, the number of credits must be calculated based on the number of megawatt hours of renewable energy used to charge the advanced electric storage technology or fill the pumped storage facility, not the number of megawatt hours actually discharged or generated by discharge from the storage facility.
The credits for Michigan-made equipment and a Michigan workforce are available for the first three years after the renewable energy system first produces electricity on a commercial basis.
Renewable Energy Credits. Renewable energy credits may be traded, sold, or otherwise transferred.
A provider is responsible for demonstrating that a credit used to comply with a renewable energy credit standard is derived from a renewable energy source and that the provider has not used or traded, sold, or otherwise transferred the credit previously.
A provider may use the same renewable energy credit to comply with both a Federal renewable energy standard and the renewable energy standard established under the Act. A provider that uses a credit to comply with another state's renewable energy standard may not use the same credit to comply with the standard established under the Act.
Credit Certification & Tracking. The PSC must establish a renewable energy credit certification and tracking program. The program may be contracted to and performed by a third party through a system of competitive bidding. The program must include all of the following:
-- A process to certify renewable energy systems, including all existing systems operating on the Act's effective date, as eligible to receive renewable energy credits.
-- A process for verifying that the operator of a renewable energy system is in compliance with State and Federal law applicable to the operation of the system when certification is granted.
-- A method for determining the date on which a credit is generated and valid for transfer.
-- A method for transferring credits.
-- A method to ensure that each credit transferred is properly accounted for.
-- If the system is established by the PSC, allowance for issuance, transfer, and use of credits in electronic form.
-- A method to ensure that both a renewable energy credit and an advanced cleaner energy credit are not awarded for the same megawatt hour of energy.
If a renewable energy system becomes noncompliant with State or Federal law, credits may not be granted for renewable energy generated by that system during the period of noncompliance.
A renewable energy credit purchased from a renewable energy system in Michigan does not have to be used in Michigan.
Advanced Cleaner Energy Credits. One advanced cleaner energy credit must be granted to the owner of an advanced cleaner energy system for each megawatt hour of electricity generated from the system. If an advanced cleaner energy system, however, uses both an advanced cleaner energy technology and another energy technology to generate electricity, the number of credits granted must be based on the percentage of the electricity generated from the advanced cleaner energy technology. If a facility or system, such as a gasification facility using biomass as feedstock, qualifies as both an advanced cleaner energy system and a renewable energy system, at the owner's option, either an advanced cleaner energy credit or a renewable energy credit, but not both, may be granted for any given megawatt hour generated by the facility or system.
An advanced cleaner energy credit expires at the earlier of the following times:
-- When substituted for a renewable energy credit or an energy optimization credit.
-- Three years after the end of the month in which the credit was generated.
Credits may be traded, sold, or otherwise transferred.
The PSC must establish an advanced cleaner energy credit tracking and certification program. The program may be contracted to and performed by a third party through a system of competitive bidding. The program must include all of the following:
-- A process to certify advanced cleaner energy systems, including all existing systems operating on the Act's effective date, as eligible to receive the credits.
-- A process for verifying that the system's operator is in compliance with State and Federal law applicable to the system's operation when certification is granted.
-- A method for determining the date on which a credit is generated and valid for transfer.
-- A method for transferring credits.
-- A method to ensure that each credit transferred is properly accounted for.
-- Allowance for issuance, transfer, and use of credits in electronic form.
-- A method to ensure that both a renewable energy credit and an advanced cleaner energy credit are not awarded for the same megawatt hour of electricity.
If an advanced cleaner energy system becomes noncompliant with State or Federal law, advanced cleaner energy credits may not be granted for energy generated by that system during the period of noncompliance.
An advanced cleaner energy credit purchased from a system in Michigan does not have to be used in Michigan.
Customer Charges. For a rate-regulated provider, the PSC must determine the appropriate charges for the provider's tariffs that permit recovery of the incremental cost of compliance subject to the retail rate impact limits set forth in the Act.
A provider must recover the incremental cost of compliance with the renewable energy standard by an itemized charge on the customer's bill for billing periods beginning not earlier than 90 days after the PSC's approval of the provider's plan or determination that the plan complies with the Act. A provider does not comply with the renewable energy standard to the extent that, as determined by the PSC, recovery of the incremental cost of compliance will have a retail rate impact that exceeds any of the following:
-- $3 per month per residential customer meter.
-- $16.58 per month per commercial secondary customer meter.
-- $187.50 per month per commercial primary or industrial customer meter.
("Customer meter" means an electric meter of a provider's retail customer. The term does not include a municipal water pumping meter or additional meters at a single site that were installed specifically to support interruptible air conditioning, interruptible water heating, net metering, or time-of-day tariffs.)
The retail rate impact limits apply only to the incremental costs of compliance and do not apply to costs approved for recovery by the PSC other than as provided in the Act.
The incremental cost of compliance must be calculated for a 20-year period beginning with approval of the plan and must be recovered on a levelized basis.
In its billing statement for a residential customer, each provider must report to the customer all of the following in a format consistent with other information on the customer bill, with the charges and savings expressed in dollars and cents:
-- An itemized monthly charge collected from the customer for implementing the renewable energy program requirements of the Act.
-- An itemized monthly charge collected from the customer for implementing the Act's energy optimization program requirements.
-- An estimated monthly saving for that customer to reflect the reductions in the monthly energy bill produced by the energy optimization program.
-- An estimated monthly saving for that customer to reflect the long-term, life-cycle, levelized costs of building and operating new conventional coal-fired electric generating power plants avoided under the Act as determined by the PSC.
-- The website address at which the PSC's annual report (described below) is posted.
Additionally, in the first bill issued after the close of the previous year, the provider must notify each residential customer that he or she may be entitled to an income tax credit to offset some of the annual amounts collected for the renewable energy program.
For the first year of the programs under Part 2, the values reported in residential customer bills must be estimates by the PSC. The values in following years must be based on the provider's actual customer experiences. If the provider is unable to supply customer-specific information regarding the energy optimization program, it must specify instead the State average itemized charge or saving, as applicable, for residential customers. The provider must make this calculation based on a method approved by the PSC.
In determining long-term, life-cycle, levelized costs of building and operating and acquiring nonrenewable electric generating capacity and energy, the PSC must consider historic and predicted costs of financing, construction, operation, maintenance, fuel supplies, environmental protection, and other appropriate elements of energy production. For purposes of this comparison, the capacity of avoided new conventional coal-fired electricity generation must be expressed in megawatt hours. Avoided costs must be measured in cents per kilowatt hour.
Implementation & Compliance Costs. Subject to the retail rate impact limits, the PSC must consider all actual costs reasonably and prudently incurred in good faith by a rate-regulated provider to implement a Commission-approved renewable energy plan, to be a cost of service to be recovered by the provider. Subject to the retail rate impact limits, a rate-regulated provider must recover through its retail electric rates all of the provider's incremental costs of compliance during the 20-year period beginning when the provider's plan is approved by the Commission and all reasonable and prudent ongoing costs of compliance during and after that period. The recovery must include the provider's authorized rate of return on equity for costs approved under these provisions, which must remain fixed at the rate of return and debt to equity ratio that was in effect in a provider's base rates when the provider's renewable energy plan was approved.
Incremental costs of compliance must be calculated by determining the sum of the following costs to the extent that they are reasonable and prudent and not already approved for recovery in electric rates as of the Act's effective date:
-- Capital, operating, and maintenance costs of renewable energy systems or advanced cleaner energy systems, including property taxes, insurance, and return on equity associated with a provider's renewable energy or advanced cleaner energy systems, including the provider's renewable energy portfolio established to achieve compliance with the renewable energy standard and any additional renewable energy systems or advanced cleaner energy systems, that the provider built or acquired to maintain compliance with the standards during the 20-year period beginning when the provider's plan is approved by the PSC.
-- Financing costs attributable to capital, operating, and maintenance costs of capital facilities associated with renewable energy systems or advanced cleaner energy systems used to meet the renewable energy standard.
-- Costs that are not otherwise recoverable in rates approved by FERC and that are related to the infrastructure required to bring renewable energy systems or advanced cleaner energy systems used to achieve compliance with the renewable energy standard on to the transmission system, including interconnection and substation costs for renewable energy or advanced cleaner energy systems used to meet the renewable energy standard.
-- Ancillary service costs determined by the PSC to be necessarily incurred to ensure the quality and reliability of renewable energy or advanced cleaner energy used to meet the renewable energy standard, regardless of the ownership of a renewable energy system or advanced cleaner energy technology.
-- Except to the extent that the costs are allocated under a different provision, the costs of renewable energy credits purchased under the Act, and the costs of renewable energy credit contracts.
-- Expenses incurred as a result of State or Federal governmental actions related to renewable energy systems or advanced cleaner energy systems attributable to the renewable energy standard, including changes in tax or other law.
-- Any additional provider costs the PSC determines to be necessarily incurred to ensure the quality and reliability of renewable energy or advanced cleaner energy used to meet the renewable energy standard.
The sum of the following revenue must be subtracted from the sum of costs not already included in electric rates determined above:
-- Revenue derived from the sale of environmental attributes associated with the generation of renewable energy or advanced cleaner energy systems attributable to the renewable energy standard.
-- Interest on regulatory liabilities.
-- Tax credits specifically designed to promote renewable energy or advanced cleaner energy.
-- Revenue derived from the provision of renewable energy or advanced cleaner energy to retail electric customers subject to a power supply cost recovery (PSCR) clause under Section 6j of the PSC law of a rate-regulated provider.
-- Revenue from wholesale renewable and advanced cleaner energy sales.
-- Any additional provider revenue the PSC considers attributable to the renewable energy standards.
(Under Section 6j of the PSC law, "power supply cost recovery clause" means a clause in a utility's electric rates or rate schedule that permits the monthly adjustment of rates for power supply to allow the utility to recover the booked costs, including transportation, reclamation, 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.)
Revenue derived from the sale of environmental attributes associated with the generation of renewable energy or cleaner energy, and revenue from wholesale renewable energy or cleaner energy sales, may not be considered in determining PSCR factors.
With regard to revenue derived from the provision of renewable or cleaner energy to retail customers subject to a PSCR clause, after providing an opportunity for a contested case hearing for a rate-regulated provider, the PSC annually must establish a price per megawatt hour. In addition, a rate-regulated provider may petition the PSC to revise the price at any time. In setting the price per megawatt hour, the PSC must consider factors including projected capacity, energy, maintenance, and operating costs; information filed under Section 6j of the PSC law; and information from wholesale markets, including locational marginal pricing. This price must be multiplied by the sum of the number of megawatt hours of renewable energy and the number of megawatt hours of advanced cleaner energy used to maintain compliance with the renewable energy standard. The product must be considered a booked cost of purchased and net interchanged power transactions under Section 6j. For energy purchased by such a provider under a renewable energy or advanced cleaner energy contract, the price must be the lower of the amount established by the PSC or the actual price paid, and must be multiplied by the number of megawatt hours of renewable or advanced cleaner energy purchased. The resulting value must be considered a booked cost of purchased and net interchanged power under Section 6j.
The PSC must authorize a rate-regulated provider to spend in any given month more to comply with the Act and implement an approved renewable energy plan than the revenue actually generated by the revenue recovery mechanism. A rate-regulated provider must recover its Commission-approved pretax rate of return on regulatory assets during the appropriate period, and must record interest on regulatory liabilities at the average short-term borrowing rate available to the provider during the appropriate period. Any regulatory assets or liabilities resulting from the recovery costs of renewable energy or advanced cleaner energy attributable to renewable energy standards through the PSCR clause under Section 6j of the PSC law must continue to be reconciled under that section.
If a provider's incremental costs of compliance in any given month during the 20-year period beginning with PSC approval of its plan exceed the adjusted revenue recovery mechanism and the balance of any accumulated reserve funds, subject to the minimum balance established by the PSC, the provider immediately must notify the PSC. The Commission promptly must commence a contested case hearing and modify the revenue recovery mechanism so that the minimum balance is restored. If the PSC determines, however, that recovery of the incremental costs of compliance would otherwise exceed the maximum retail rate impacts, it must set the revenue recovery mechanism for that provider to correspond to the maximum retail rate impacts. Excess costs must be accrued and deferred for recovery. For a rate-regulated provider, before the expiration of the 20-year period beginning with PSC approval of its plan, the PSC must determine the amount of deferred costs to be recovered under the revenue recovery mechanism and the recovery period, which may not extend more than five years beyond the expiration of the 20-year period. The recovery of excess costs must be proportional to the retail rate impact limits for each customer class. The recovery of excess costs alone, or, if begun before the expiration of the 20-year period, in combination with the recovery of incremental costs of compliance under the revenue recovery mechanism, may not exceed the retail rate impact limits for each customer class.
If a rate-regulated provider has a regulatory liability at the expiration of the 20-year period, the refund to customer classes must be proportional to the amounts they paid under the revenue recovery mechanism.
After achieving compliance with the renewable energy standard for 2015, the actual costs reasonably and prudently incurred to continue to comply with Subpart A both during and after the conclusion of the 20-year period must be considered costs of service. The PSC must determine a mechanism for a rate-regulated provider to recover these costs in its retail electric rates, subject to the limits prescribed in the Act. Remaining and future regulatory assets must be recovered consistent with the Act's method for calculating incremental costs of compliance, the provisions pertaining to recovery of additional costs beyond the revenue recovery mechanism, and the provisions related to renewable cost reconciliation.
Renewable Cost Reconciliation for Regulated Providers. These provisions apply only to an electric provider whose rates are regulated by the PSC.
Concurrent with the submission of each report regarding a provider's actions to comply with the renewable portfolio standard, the PSC must commence an annual proceeding, to be known as a renewable cost reconciliation, for each rate-regulated provider. The reconciliation proceeding must be conducted as a contested case hearing under the APA. Reasonable discovery must be permitted before and during the proceeding to assist in obtaining evidence concerning reconciliation issues, including the reasonableness and prudence of expenditures and the amounts collected pursuant to the revenue recovery mechanism.
At the reconciliation, a provider may propose any necessary modifications of the revenue recovery mechanism to ensure the provider's recovery of its incremental cost of compliance with the renewable energy standard.
The PSC must reconcile the pertinent revenue recorded and the allowance for the nonvolumetric revenue recovery mechanism with the amounts actually expensed and projected according the provider's plan for compliance. The PSC must consider any issue regarding the reasonableness and prudence of expenses for which customers were charged in the relevant reconciliation period. In its order, the PSC must do all of the following:
-- Determine the provider's compliance with the renewable energy standard, subject to the extension provisions.
-- Adjust the revenue recovery mechanism for the incremental costs of compliance.
-- Establish the price per megawatt hour for renewable energy and advanced cleaner energy capacity, and for renewable energy and advanced cleaner energy to be recovered through the PSCR clause, as outlined above.
-- Adjust the minimum balance of accumulated reserve funds established by the PSC, if necessary.
With regard to the adjustment of the revenue recovery mechanism, the PSC must ensure that the retail rate impacts under the renewable cost reconciliation revenue recovery mechanism do not exceed the maximum retail rate impacts specified in the Act. The PSC must ensure that the recovery mechanism is projected to maintain a minimum balance of accumulated reserve so that a regulatory asset does not accrue.
If a provider has recorded a regulatory liability in any given month during the 20-year period beginning with the PSC's approval of the provider's plan, interest on the regulatory liability balance must be accrued at the average short-term borrowing rate available to the provider during the appropriate period, and must be used to fund incremental costs of compliance incurred in subsequent periods within that 20-year period.
Provider & PSC Reports. By a time the PSC determines, each electric provider must submit to the Commission an annual report that provides information relating to the provider's actions to comply with the renewable energy standard. By the same time, a municipally owned electric utility must submit a copy of the report to its governing body, and a cooperative electric utility must submit a copy of the report to its board of directors.
Each annual report must include all of the following information:
-- The amount of electricity and renewable energy credits that the provider generated or acquired from renewable energy systems during the reporting period and the amount of renewable energy credits that the provider acquired, sold, traded, or otherwise transferred during that period.
-- The amount of electricity that the provider generated or acquired from advanced cleaner energy systems pursuant to the Act during the reporting period.
-- The capacity of each renewable energy system and advanced cleaner energy system owned, operated, or controlled by the provider, the total amount of electricity generated by each renewable energy system or advanced cleaner energy system during the reporting period, and the percentage of that total amount of electricity from each renewable energy system that was generated directly from renewable energy.
-- Whether the provider began construction on, acquired, or placed into operation a renewable energy system or advanced cleaner energy system during the reporting period.
-- Expenditures made in the past year and anticipated future expenditures to comply with Subpart A.
-- Any other information that the PSC determines necessary.
Concurrently with the submission of each report, a municipally owned electric utility must submit a summary of the report to its customers with a bill insert and to its governing body, and a cooperative electric utility must submit a summary to its members in a periodical issued by an association of rural electric cooperatives and to its board of directors. The utility or provider must make a copy of the report available at its office and post a copy on its website. A summary must indicate that a copy of the report is available at the office or website.
The PSC must monitor the reports and ensure that actions taken under the Act by providers serving customers in the same distribution territory do not create an unfair competitive advantage for any of those providers.
By February 15, 2011, and each year after that, the PSC must submit a report to the standing committees of the Senate and House of Representatives with primary responsibility for energy and environmental issues. The report must do all of the following:
-- Summarize data collected under these provisions.
-- Discuss the status of renewable and advanced cleaner energy in Michigan and the effect of Subparts A and B (Energy Optimization) on electricity prices.
-- Specify the difference between the cost of the renewable energy and the cost of electricity generated from new conventional coal-fired electric generating facilities, for each of the different types of renewable energy sold at retail in Michigan.
-- Discuss how the PSC is fulfilling the requirements of monitoring the reports and ensuring that actions taken under the Act by providers serving customers in the same distribution territory do not create an unfair competitive advantage for any of those providers.
-- Evaluate whether Subpart A has been cost-effective.
-- Compare the cost-effectiveness of the methods of an electric utility with at least 1.0 million retail customers in Michigan as of January 1, 2008, obtaining renewable energy credits under the options described in the Act.
-- Describe the impact of Subpart A on employment in Michigan.
-- Describe the effect of the percentage limits on energy optimization and advanced cleaner energy credits on the development of advanced cleaner energy.
-- Make any recommendations the PSC has concerning amendments to Subpart A, including changes in the percentage limits, or changes in the definition of "renewable energy resource" or "renewable energy system" to reflect environmentally preferred technology.
In describing the impact of Subpart A on employment, the PSC must consult with other appropriate agencies of the Department of Energy, Labor, and Economic Growth (DELEG) in the development of this information.
The Department must maintain a copy of the PSC's most recent report on its website.
Failure to Meet Act's Requirements. If a rate-regulated provider fails to meet the renewable energy credit standard by the applicable deadline, subject to the provisions regarding extensions, the provider must purchase sufficient renewable energy credits necessary to meet the standard. The provider may not recover from its ratepayers the cost of purchasing renewable energy credits if the PSC finds that the provider did not make a good faith effort to meet the renewable energy standard by the applicable deadline, subject to the extension provisions.
The Attorney General or any customer of a member-regulated cooperative electric utility may bring a civil action for injunctive relief against the utility if it fails to meet the applicable requirements of Subpart A or an order issued or rule promulgated under it.
An action must be brought in the circuit court for the circuit in which the cooperative utility's principal office is located. An action may not be filed unless the prospective plaintiff has given the utility and the PSC at least 60 days' written notice of the prospective plaintiff's intent to sue, the basis for the suit, and the relief sought. Within 30 days after the utility receives notice of the intent to sue, the parties must meet and make a good faith attempt to determine if there is a credible basis for the action. If both parties agree that there is, the utility must take all reasonable and prudent steps necessary to comply with the applicable requirements of Subpart A within 90 days of the meeting.
Upon receiving a complaint of an AES's customer or on the PSC's own motion, the PSC may conduct a contested case to review allegations that the AES has violated the Subpart A, including an order issued or rule promulgated under it. If the PSC finds, after notice and hearing, that an AES has violated Subpart A or an order or rule, the Commission must do at least one of the following:
-- Revoke the AES's license.
-- Issue a cease and desist order.
-- Order the AES to pay a civil fine of at least $5,000 but not more than $50,000 for each violation.
Upon receiving a compliant by a customer of a municipally owned electric utility or upon the PSC's own motion, the Commission may review allegations that the utility has violated Subpart A or an order issued or rule promulgated under it. If the PSC finds, after notice and hearing, that the utility has committed a violation, it must advise the Attorney General. The Attorney General may commence a civil action for injunctive relief against the municipally owned utility in the circuit court for the circuit in which the utility's principal office is located.
In issuing a final order in an action brought against a cooperative utility or a municipally owned electric utility, the court may award costs of litigation, including reasonable attorney and expert witness fees, to the prevailing or substantially prevailing party.
Subpart B: Energy Optimization
Energy Optimization Plan; Goal. A provider must file a proposed energy optimization plan with the PSC within the following time period:
-- For a rate-regulated provider, 90 days after the PSC issues a temporary order implementing the Act.
-- For a member-regulated cooperative electric utility or a municipally owned electric utility, 120 days after the PSC issues its temporary order.
(For purposes of Subpart B, "provider" means an electric provider or a natural gas provider. "Natural gas provider" means an investor-owned business engaged in the sale and distribution of natural gas within Michigan whose rates are regulated by the PSC. As used in Subpart B, "electric provider" and "natural gas provider" do not include a licensed AES or alternative gas supplier.)
The overall goal of an energy optimization (EO) plan must be to reduce the future costs of provider service to customers. In particular, the plans must be designed to delay the need for constructing new electric generating facilities, thereby protecting consumers from incurring the costs of their construction. A proposed EO plan is subject to approval in the same manner as a provider's renewable energy plan under Subpart A. A provider may combine its EO plan with its renewable energy plan.
An EO plan must do all of the following:
-- Propose a set of EO programs that include offerings for each customer class, including low-income residential.
-- Specify necessary funding levels.
-- Describe how EO program costs will be recovered from customers through itemized charges on their utility bills.
-- Ensure that charges collected from a particular customer rate class are spent on EO programs for that rate class, to the extent feasible.
-- Demonstrate that the proposed EO programs and funding are sufficient to ensure the achievement of applicable EO standards.
-- Specify whether the number of megawatt hours of electricity or decatherms of MCFs of natural gas used in the calculation of incremental energy savings under the Act will be weather-normalized or based on the average number of megawatt hours of electricity or decatherms or MCFs of natural gas sold by the provider annually during the previous three years to Michigan retail customers.
-- Demonstrate that the provider's EO programs, excluding program offerings to low-income residential customers, collectively will be cost-effective.
-- Provide for the practical and effective administration of the proposed EO programs.
-- Include a process for obtaining an independent expert evaluation of the actual EO programs to verify the incremental energy savings from each program for purposes of Section 77 (which establishes minimum energy savings that EO programs must achieve).
The PSC must allow each provider flexibility to tailor the relative amount of effort devoted to each customer class based on the specific characteristics of its service territory. The option for calculating incremental energy savings may not be changed once the PSC approves the plan. With regard to administration of EO programs, the PSC must allow providers flexibility in designing their programs and administrative approach. A provider's EO programs or any part of them may be administered, at the provider's option, by the provider, alone or jointly with other providers, by a State agency, or by an appropriate experienced nonprofit organization selected after a competitive bid process. All independent expert evaluations are subject to public review and PSC oversight.
In addition, an EO plan may do one or more of the following, as long as expenditures do not exceed 3% of the costs of implementing the plan:
-- Use educational programs designed to alter consumer behavior or any other measures that reasonably can be used to meet the goals set forth in the Act.
-- Propose to the Commission measures that are designed to meet the prescribed goals and that provide additional customer benefits.
PSC Review of Plans. A provider's EO plan must be filed, reviewed, and approved or rejected by the PSC and enforced subject to the same procedures that apply to the renewable energy plan.
The PSC may not approve a proposed EO plan unless the Commission determines that the plan meets the utility system resource cost test and is reasonable and prudent. In making this determination, the PSC must review each element and consider whether it would reduce the future cost of service for the provider's customers. ("Utility system resource cost test" means a standard that is met for an investment in energy optimization if, on a life-cycle basis, the total avoided supply-side costs to the provider, including representative values for electricity or natural gas supply, transmission, distribution, and other associated costs, are greater than the total costs to the provider of administering and delivering the EO program, including net costs for any provider incentives paid by customers and capitalized costs recovered under the Act.)
In addition, the PSC must consider at least all of the following:
-- The specific changes in customers' consumption patterns that the proposed EO plan is attempting to influence.
-- The cost and benefit analysis and other justification for specific programs and measures included in a public utility's proposed EO plan.
-- Whether the proposed EO plan is consistent with any long-range resource plan filed by the provider with the PSC.
-- Whether the proposed EO plan will result in any unreasonable prejudice or disadvantage to any customer class.
-- The extent to which the plan provides programs that are available, affordable, and useful to all customers.
Financial Incentives. The EO plan of a rate-regulated provider may authorize a commensurate financial incentive for the provider for exceeding the EO performance standard. Payment of any authorized financial incentive is subject to PSC approval. The total amount of a financial incentive may not exceed the lesser of the following amounts: 25% of the net cost reductions experienced by the provider's customers as a result of implementation of the EO plan, or 15% of the provider's actual energy efficiency program expenditures for the year.
Minimum Energy Savings. Except as otherwise provided and subject to the sales revenue expenditure limits prescribed in the Act, an electric provider's EO programs collectively must achieve the following minimum energy savings:
-- Biennial incremental energy savings in 2008-2009 equivalent to 0.3% of total annual retail electricity sales in megawatt hours in 2007.
-- Annual incremental energy savings in 2010 equivalent to 0.5% of total annual retail electricity sales in megawatt hours in 2009.
-- Annual incremental energy savings in 2011 equivalent to 0.75% of total annual retail electricity sales in megawatt hours in 2010.
-- Annual incremental energy savings in 2012, 2013, 2014, and 2015 and, subject to other provisions, each subsequent year equivalent to 1.0% of total annual retail electricity sales in megawatt hours in the preceding year.
If an electric provider uses load management to achieve energy savings under its EO plan, the required minimum energy savings must be adjusted so that the ratio of the minimum energy savings to the sum of maximum expenditures prescribed in the Act and the load management expenditures remains constant.
A natural gas provider must meet the following minimum energy optimization standards using energy efficiency programs under Subpart B:
-- Biennial incremental energy savings in 2008-2009 equivalent to 0.1% of total retail natural gas sales in decatherms or equivalent MCFs in 2007.
-- Annual incremental energy savings in 2010 equivalent to 0.25% of total retail natural gas sales in 2009.
-- Annual incremental energy savings in 2011 equivalent to 0.5% of total retail natural gas sales in 2010.
-- Annual incremental energy savings in 2012, 2013, 2014, and 2015 and, subject to other provisions, each subsequent year equivalent to 0.75% of total annual retail natural gas sales in the preceding year.
Incremental energy savings for the 2008-2009 biennium or any subsequent year must be determined for a provider by adding the energy savings expected to be achieved during a one-year period by EO measures implemented during the 2008-2009 biennium or any subsequent year under any energy efficiency programs consistent with the provider's energy efficiency plan.
For purposes of calculations regarding the energy savings, total annual retail electricity or natural gas sales in a year must be based on one of the following at the option of the provider as specified in its EO plan:
-- The number of weather-normalized megawatt hours or decatherms or equivalent MCFs sold by the provider during the three years preceding the biennium or year for which incremental energy savings are being calculated.
-- The average number of megawatt hours or decatherms or equivalent MCFs sold by the provider during the three years preceding the biennium or year for which incremental energy savings are being calculated.
For any year after 2012, an electric provider may substitute renewable energy credits associated with renewable energy generated that year from a renewable energy system constructed after the Act's effective date, advanced cleaner energy credits other than credits from industrial cogeneration using industrial waste energy, load management that reduces overall energy usage, or a combination of those methods for EO credits otherwise required to meet the EO performance standard, if the PSC approves the substitution. The PSC may not approve a substitution unless it determines that the substitution is cost-effective and, if the substitution involves advanced cleaner energy credits, that the advanced cleaner energy system provides carbon dioxide emissions benefits. In determining whether the substitution of advanced cleaner energy credits is cost-effective compared to other available EO measures, the PSC must consider the environmental costs related to the advanced cleaner energy system, including the costs of environmental control equipment or greenhouse gas constraints or taxes. The PSC's determinations must be made after a contested case hearing that includes consultation with the Department of Environmental Quality on the issue of carbon dioxide emissions benefits, if relevant, and environmental costs.
A provider may not use renewable energy credits, advanced cleaner energy credits, load management that reduces overall electricity usage, or a combination of those methods to meet more than 10% of the EO standard. Substitutions for EO credits must be made at the following rates per EO credit:
-- One renewable energy credit.
-- One advanced cleaner energy credit from plasma arc gasification.
-- Four advanced cleaner energy credits other than from plasma arc gasification.
Advanced cleaner energy systems that are the source of the advanced cleaner energy credits used under these provisions must be either located outside Michigan in the service territory of any electric provider that is not an AES, or located anywhere in this State.
Alternative EO Standards. These provisions apply to electric providers that serve a maximum of 200,000 Michigan customers and had average electric rates for residential customers using 1,000 kilowatt hours per month that are less than 75% of the average electric rates for those customers for all electric utilities in Michigan, according to the January 1, 2007, "Comparison of averages rates for MPSC-regulated electric utilities in Michigan", complied by the PSC.
Beginning two years after the provider begins implementation of its EO plan, the provider may petition the PSC to establish alternative EO standards. The petition must identify the provider's efforts to meet the electric provider EO standards and demonstrate why the standards cannot reasonably be met with EO programs that collectively are cost-effective. If the PSC finds that the petition meets the Act's requirements, it must revise the standards as applied to that provider to a level that can reasonably be met with EO programs that collectively are cost-effective.
Energy Optimization Credits. One EO credit must be granted to a provider for each megawatt hour of annual incremental energy savings achieved through energy optimization. An EO credit expires when used by a provider to comply with its EO performance standard, when substituted for a renewable energy credit under the Act, or as provided below.
If a provider's incremental energy savings in the 2008-2009 biennium or any following year exceed the applicable EO standard, the associated EO credits may be carried forward and applied to the next year's EO standard. The number of credits carried forward, however, may not exceed one-third of the next year's standard. Any EO credits carried forward to the next year expire that year. Any remaining credits expire at the end of the year in which the incremental energy savings were achieved, unless substituted, by an electric provider, for renewable energy credits. In addition, EO credits may not be carried forward if, for its performance during the same biennium or year, the provider accepts a financial incentive. The excess credits expire at the end of the year in which the incremental energy savings were achieved, unless substituted, by an electric provider, for renewable energy credits.
Transfer of EO Credits. An EO credit is not transferable to another entity. In the 2011 report required under Section 97, the PSC must make recommendations concerning a program for transferability of the credits. (Section 97, described below, requires a provider to submit to the PSC a report regarding its actions to comply with the EO standards.)
Energy Optimization Credit Tracking & Certification. The PSC must establish an EO credit certification and tracking program. The program may be contracted to and performed by a third party through a system of competitive bidding. The program must include all of the following:
-- A determination of the date after which energy optimization must be achieved to be eligible for an EO credit.
-- A method for ensuring that each EO credit substituted for a renewable energy credit or carried forward is properly accounted for.
-- Allowance for issuance and use of EO credits in electronic form, if the system is established by the PSC.
Energy Optimization Plan Cost Recovery. The PSC must allow a rate-regulated provider to recover the actual costs of implementing its approved EO plan. Costs exceeding the overall funding levels specified in the plan, however, are not recoverable unless they are reasonable and prudent and meet the utility system resource cost test. Also, costs for load management undertaken pursuant to an EO plan are not recoverable as program costs under these provisions, but may be recovered as part of a preceding under Section 6 of the PSC law (which vests the PSC with jurisdiction to regulate all public utilities in the State, subject to certain exceptions, and authorizes the PSC to hear and pass upon all matters pertaining to, necessary, or incident to the regulation of public utilities).
Implementation costs must be recovered from all natural gas customers and from residential electric customers by volumetric charges, from all other metered electric customers by per-meter charges, and from unmetered electric customers by an appropriate charge, applied to utility bills as an itemized charge.
For the electric primary customer rate class customers of electric providers and customers of natural gas providers with an aggregate annual natural gas billing demand of more than 100,000 decatherms or equivalent MCFs for all sites in the natural gas utility's service territory, the cost recovery may not exceed 1.7% of total retail sales revenue for that customer class. For electric secondary customers and for residential customers, the cost recovery may not exceed 2.2% of total retail sales revenue for those customer classes.
Upon petition by a rate-regulated provider, the PSC must authorize it to capitalize all energy efficiency and energy conservation equipment, materials, and installation costs with an expected economic life greater than one year incurred in implementing its EO plan, including such costs paid to third parties, such as customer rebates and customer incentives. The provider also must propose depreciation treatment with respect to its capitalized costs in its EO plan, and the PSC must order reasonable depreciation treatment related to these capitalized costs. A provider may not capitalize payments made to an independent energy optimization program administrator (described below).
The established funding level for low-income residential programs must be provided from each customer rate class in proportion to its funding of the provider's total EO programs. Charges must be applied to distribution customers regardless of the source of their electricity or natural gas supply.
The PSC must authorize a natural gas provider that spends a minimum of 0.5% of total natural gas retail sales revenue, including natural gas commodity costs, in a year on PSC-approved EO programs to implement a symmetrical revenue decoupling true-up mechanism that adjusts for sales volumes that are above or below the projected levels that were used to determine the revenue requirement authorized in the provider's most recent rate case. In determining the true-up mechanism used for each provider, the PSC must give deference to the mechanism proposed by the provider. The PSC may approve an alternate mechanism if it determines that the alternative mechanism is reasonable and prudent. The PSC must authorize the provider to decouple rates regardless of whether the provider's EO programs are administered by the provider or an independent program administrator.
A natural gas or electric provider may not spend more than the following percentage of total utility retail sales revenue, including electricity or natural gas commodity costs, in any year to comply with the EO performance standard without specific approval from the PSC:
-- In 2009, 0.75% of total retail sales revenue for 2007.
-- In 2010, 1.0% of total retail sales revenue for 2008.
-- In 2011, 1.5% of total retail sales revenue for 2009.
-- In 2012 and each following year, 2.0% of total retail sales revenue for the two preceding years.
Energy Optimization Program Administrator. The Act's provisions regarding energy optimization plans and standards do not apply to a provider that pays the following percentage of total utility sales revenue, including electricity or natural gas commodity costs, each year to an independent EO program administrator selected by the PSC:
-- In 2009, 0.75% of total retail sales revenue for 2007.
-- In 2010, 1.0% of total retail sales revenue for 2008.
-- In 2011, 1.5% of total retail sales revenue for 2009.
-- In 2012 and each subsequent year, 2.0% of total retail sales revenue for the two preceding years.
Section 89(6), however, continues to apply to such a provider. (That section requires the PSC to authorize a natural gas provider that spends a minimum of 0.5% of total natural gas retail sales revenue, including natural gas commodity costs, in a year on Commission-approved EO programs to implement a symmetrical revenue decoupling true-up mechanism, as described above.)
An alternative compliance payment the program administrator receives from a provider must be used to administer energy efficiency programs for the provider.
The PSC must allow a provider to recover an alternative compliance payment. This cost must be recovered from residential customers by volumetric charges, from all other metered customers by per-meter charges, and from unmetered customers by an appropriate charge, applied to utility bills.
An alternative compliance payment paid to the program administrator may be used only to fund energy optimization programs for that provider's customers. To the extent feasible, charges collected from a particular customer rate class and paid to the administrator must be devoted to EO programs for that rate class. Subject to these requirements, money paid to the administrator that it does not spend that year must remain available for expenditure the following year.
The PSC must select a qualified nonprofit organization to serve as the administrator through a competitive bid process. The Commission also must arrange for a biennial audit of the administrator.
Self-Directed EO Plan. An eligible primary or secondary electric customer is exempt from charges the customer would otherwise incur for EO programs if the customer files with its electric provider and implements a self-directed EO plan.
To be eligible, in 2009 or 2010, the customer must have had an annual peak demand in the preceding year of at least two megawatts at each site to be covered by the self-directed plan or five megawatts in the aggregate at all sites to be covered by that plan.
In 2011, 2012, or 2013, the customer or customers must have had an annual peak demand in the preceding year of at least one megawatt at each site to be covered by the self-directed plan or five megawatts in the aggregate at all sites to be covered.
In 2014 or any following year, the customer or customers must have had an annual peak demand in the preceding year of at least one megawatt in the aggregate at all sites to be covered by the self-directed plan.
The PSC must establish by order the rates, terms, and conditions of service for customers related to Subpart B.
The PSC also must do all of the following by order:
-- Require a customer to use the services of an EO service company to develop and implement a self-directed plan (unless the customer had an annual peak demand in the preceding year of at least two megawatts at each site to be covered by the plan or 10 megawatts in the aggregate at all sites to be covered).
-- Provide a mechanism to recover from customers who implement a self-directed plan the costs for provider-level review and evaluation.
-- Provide a mechanism to cover the costs of the low income EO program.
A self-directed plan must be a multiyear plan for an ongoing EO program. The plan must provide for aggregate energy savings that for each year meet or exceed the EO performance standards based on the electricity purchases in the previous year for the covered site or sites. Under the plan, energy optimization must be calculated based on annual electricity usage. Annual usage must be normalized so that none of the following are included in the calculation of the percentage of incremental energy savings:
-- Changes in electricity usage because of changes in business activity levels not attributable to energy optimization.
-- Changes in electricity usage because of the installation, operation, or testing of pollution control equipment.
A self-directed plan must specify whether electricity usage will be weather-normalized or based on the average number of megawatt hours of electricity sold by the provider annually during the previous three years to retail customers in Michigan. Once the plan is submitted to the provider, this option may not be changed.
In addition, the plan must outline how the customer intends to achieve its specified incremental energy savings.
A self-directed EO plan must be incorporated into the relevant provider's EO plan. The self-directed plan and information submitted by the customer are confidential and exempt from disclosure under the Freedom of Information Act. Projected energy savings from measures implemented under a self-directed plan must be attributed to the relevant provider's EO programs for the purposes of determining annual incremental energy savings the provider achieves, as applicable.
Once a customer begins to implement a self-directed plan at a site covered by the plan, that site is exempt from EO program charges and is not eligible to participate in the relevant provider's EO programs.
A customer implementing a self-directed plan must submit to the customer's electric provider every two years a brief report documenting the energy efficiency measures taken under the plan during that two-year period, and the corresponding energy savings that will result. The report must provide sufficient information for the provider and the PSC to monitor progress toward the goals in the self-directed plan and to develop reliable estimates of the energy savings that are being achieved from self-directed plans. A customer promptly must notify the provider if the customer fails to achieve incremental energy savings as set forth in its self-directed plan for a year that will be the first year covered by the next biannual report. If a customer submitting a report or notice wishes to amend its self-directed plan, the customer must submit with the report or notice an amended plan. A report must be accompanied by an affidavit from a knowledgeable official of the customer that the information in the report is true and correct to the best of the official's knowledge and belief. If the customer has retained an independent EO service company, it must meet these requirements.
An electric provider must give the PSC an annual report that identifies customers implementing self-directed plans and summarizes the results achieved cumulatively under those plans. The PSC may request additional information from the provider. IF the PSC has sufficient reason to believe the information is inaccurate or incomplete, it may request additional information from the customer to ensure accuracy of the report.
If the PSC determines after a contested case hearing that the specified minimum EO goals have not been achieved at the sites covered by a self-directed plan, in aggregate, it must order the customer or customers collectively to pay to the State an amount calculated as follows:
-- Determine the proportion of the shortfall in achieving the minimum EO goals.
-- Multiply that figure by the EO charges from which the customer or customers collectively were exempt.
-- Multiply the product by a number not less than one or greater than two, as determined by the PSC based on the reasons for failure to meet the minimum EO goals.
If a customer has submitted a self-directed plan to a provider, the customer, the customer's EO service company, if applicable, or the provider must give a copy of the plan to the PSC upon request.
By September 1, 2010, following a public hearing, the PSC must establish an approval process for EO service companies. The approval process must ensure that the companies have the expertise, resources, and business practices reliably to provide EO services that meet the Act's requirements. The PSC may adopt by reference the past or current standards of a national or regional certification or licensing program for EO service companies. The approval process, however, also must provide an opportunity for companies that are not recognized by such a program to be approved by posting a bond in an amount determined by the PSC and meeting any other requirements adopted by the PSC for the purposes of these provisions. The approval process must require adherence to a code of conduct governing the relationship between EO service companies and electric providers.
The Department of Labor and Economic Growth must maintain on its website a list of approved EO service companies.
PSC Duties. The PSC must do all of the following:
-- Promote load management in appropriate circumstances.
-- Actively pursue increasing public awareness of load management techniques.
-- Engage in regional load management efforts to reduce the annual demand for energy whenever possible.
-- Work with residential, commercial, and industrial customers to reduce annual demand and conserve energy through load management techniques and other activities it considers appropriate.
By December 31, 2010, the PSC must file with the Legislature a report on the effort to reduce peak demand. The report also must include any recommendations for legislative action concerning load management that the PSC considers necessary.
The PSC may allow a rate-regulated provider to recover costs for load management undertaken pursuant to an EO plan through base rates as part of a proceeding under the PSC law, if the costs are reasonable and prudent and meet the utility systems resource cost test.
Additionally, the PSC must do all of the following:
-- Promote energy efficiency and conservation.
-- Actively pursue increasing public awareness of energy conservation and energy efficiency.
-- Actively engage in energy conservation and energy efficiency efforts with providers.
-- Engage in regional efforts to reduce demand for energy through energy conservation and energy efficiency.
By November 30, 2009, and each following year, the PSC must submit to the standing committees of the Legislature with primary responsibility for energy and environmental issues a report on the effort to implement energy conservation and energy efficiency programs or measures. The report may include any recommendations of the PSC for energy conservation legislation.
Subpart B does not limit the PSC's authority, following an integrated resource plan proceeding and as part of a rate-making process, to allow a rate-regulated provider to recover for additional prudent energy efficiency and conservation measures not included in the provider's EO plan if the provider has met the requirements of the EO program.
Provider & PSC Reports. By a time determined by the PSC, each provider must submit to the Commission an annual report that provides information relating to the provider's actions taken to comply with the EO standards. By the same time, a municipally owned electric utility must submit a copy of the report to its governing body, and a cooperative electric utility must submit a copy to its board of directors. An annual report must include the following information:
-- The number of EO credits that the provider generated during the reporting period.
-- Expenditures made in the past year and anticipated future expenditures to comply with Subpart B.
-- Any other information that the PSC determines necessary.
Concurrently with the submission of each annual report, a municipally owned electric utility must submit a summary to its customers with a bill insert and to its governing body, and a cooperative electric provider must submit a summary to its members in a periodical issued by an association of rural electric cooperatives and to its board of directors. The utility or provider must make a copy of the report available at its office and post a copy on its website. A summary must indicate that a copy of the report is available at the office or website.
Within one year after the Act's effective date, the PSC must submit a report on the potential rate impacts on all customer classes if rate-regulated providers decouple rates. The report must be submitted to the standing committees of the Legislature with primary responsibility for energy and environmental issues. The report must review whether decoupling would be cost-effective and would reduce the overall consumption of fossil fuels in Michigan.
By October 1, 2010, the PSC must submit to the specified legislative committees any recommendations for legislative action to increase energy conservation and efficiency based on providers' annual reports, the approved EO plans, and the Commission's own investigation. By March 1, 2013, the PSC must submit to those committees a report on the progress of electric providers in achieving reductions in energy use. The PSC may use an independent evaluator to review the submissions by providers.
By February 15, 2011, and each following year, and by September 30, 2015, the PSC must submit to the specified legislative committees a report that evaluates and determines whether Subparts A and B have each been cost-effective and makes recommendations to the Legislature. The report must be combined with any concurrent report by the Commission under Section 51 (which requires the PSC to submit a report on renewable energy and advanced cleaner energy). The report required by September 30, 2015, also must review the opportunities for additional cost-effective EO programs and make any recommendations the PSC has for legislation providing for the continuation, expansion, or reduction of EO standards. In addition, the report must include the PSC's determinations of all of the following:
-- The percentage of total energy savings required by the EO standards that actually have been achieved by each electric provider and by all electric providers cumulatively.
-- The percentage of total energy savings required by the EO standards that actually have been achieved by each natural gas provider and by all natural gas providers cumulatively.
-- For each provider, whether its program under Subpart B has been cost-effective.
If the PSC determines in that report or determines subsequently that a provider's EO program has not been cost-effective, the program will be suspended beginning 180 days after the date of the report or subsequent determination. If an EO program is suspended, the provider must maintain cumulative incremental energy savings in megawatt hours or decatherms or equivalent MCFs in subsequent years at the level actually achieved during the year preceding the year in which the Commission makes its determination. Additionally, the provider may not impose EO charges in subsequent years except to the extent necessary to recover unrecovered EO expenses incurred under Subpart B before suspension of the program.
Subpart C: Miscellaneous
Subpart C states that Part 2 does not give the PSC any new authority with respect to municipally owned electric utilities except to the extent expressly provided in the Act.
Notwithstanding any other provision of Part 2, electricity or natural gas used in the installation, operation, or testing of any pollution control equipment is exempt from the requirements of, and calculations of compliance required under, Part 2.
Part 3: State Government Energy Efficiency & Conservation
Energy Use Reduction Goal
The Act states, "It is the goal of this state to reduce state government grid-based energy purchases by 25% by 2015, when compared to energy use and energy purchases for the state fiscal year ending September 30, 2002."
DMB & Energy Office
The Department of Management and Budget (DMB), after consultation with the Energy Office in DELEG, must establish a program for energy analysis of each State building that identifies opportunities for reduced energy use, including the cost and energy savings for each opportunity, and includes a completion schedule. Under the program, the Energy Star assessment and rating program must be extended to all buildings owned or leased by the State. An energy analysis of each building must be conducted at least every five years. Within one year after the Act's effective date, an energy analysis must be conducted of any building for which an analysis was not conducted within five years before the Act took effect. If building or facility modifications are allowed under the terms of a lease, the State must undertake any recommendations resulting from an energy audit to those facilities if they will save money.
Before the State leases a building, the DMB, after consultation with the Energy Office, must examine the cost and benefit of leasing a building that meets LEED (Leadership in Energy and Environmental Design) building code standards, or remodeling a building to meet such standards. The State must take into consideration whether a building has historical, architectural, or cultural significance that could be harmed if a lease were not renewed solely based on the building's failure to meet LEED criteria.
In addition, after consulting with the Energy Office, the DMB must do the following:
-- Examine the cost and benefit of using LEED building code standards when constructing or remodeling a State building.
-- Assist each State department in appointing an energy reduction coordinator to work with the DMB and the Energy Office to reduce State energy use.
-- Ensure that, during any renovation or construction of a State building, energy efficient products are used whenever possible and that the State purchases energy efficient products whenever possible.
-- Implement a program, which the Energy Office and the DMB must update every three years, to educate State employees on how to conserve energy.
-- Use more cost-effective lighting technologies, geothermal heat pumps, and other cost-effective technologies to conserve energy.
-- Reduce State government energy use during peak summer energy use seasons with the goal of achieving reductions beginning in 2010.
-- Create a web-based system for tracking energy efficiency and conservation projects occurring within State government.
Part 4: Wind Energy Resource Zones
Wind Energy Resource Zone Board
Within 60 days after the Act's effective date, the PSC must create the Wind Energy Resource Zone Board, which must exercise its powers, duties, and decision-making authority independently of the Commission. The Board must consist of two members representing the electric utility industry and one member representing each of the following:
-- The PSC.
-- AESs.
-- The Attorney General.
-- The renewable energy industry.
-- Cities and villages.
-- Townships.
-- Independent transmission companies.
-- A statewide environmental organization.
-- The public at large.
In consultation with local governments, the Board must study wind energy production potential and the viability of wind as a source of commercial energy generation in Michigan, and the availability of land in Michigan for potential use by wind energy conversion systems.
Additionally, the Board must conduct modeling and other studies related to wind energy, including the study of existing wind energy conversion systems, estimates for additional wind energy conversion system development, and average annual recorded wind velocity levels. The Board's studies also must include examination of wind energy conversion system requests currently in the applicable regional transmission organization's (RTO's) generator interconnection queue.
("Wind energy conversion system" means a renewable energy system that uses one or more wind turbines to generate electricity and has a nameplate capacity of 100 kilowatts or more.)
Within 240 days after the Act's effective date, the Board must issue a report detailing its findings, including all of the following:
-- A list of regions in the State with the highest level of wind energy harvest potential.
-- A description of the estimated maximum and minimum wind capacity in megawatts that can be installed in each identified region.
-- An estimate of the annual maximum and minimum energy production potential for each identified region.
-- An estimate of the maximum wind generation capacity already in service in each identified region.
The Board must submit a copy of the proposed report to the legislative body of each local unit of government located in whole or part within any listed region. The legislative body may submit comments to the Board within 63 days after the report was submitted to it. After the deadline for submitting comments, the Board must hold a public hearing on the proposed report. The Board may hold a separate public hearing in each listed region. The Board must give written notice of a hearing to the legislative body of each local unit located in whole or part within the region or regions that are the subject of the hearing, and must publish the notice in a newspaper of general circulation within the region or regions. Within 45 days after satisfying these requirements, the Board must issue a final report.
After the Board issues its report, electric utilities, affiliated transmission companies and independent transmission companies with transmission facilities within or adjacent to regions of the State identified in the report must identify existing or new transmission infrastructure necessary to deliver maximum and minimum wind energy production potential for each of those regions, and must submit this information to the Board for its review.
Wind Energy Resource Zones. Based on the Board's findings, the PSC, through a final order, must designate an area of the State likely to be most productive of wind energy as the primary wind energy resource zone, and may designate additional zones. A wind energy resource zone must be created on land that is entirely within the State's boundaries. A zone must encompass a natural geographical area or region of the State. A wind zone must exclude land that is zoned residential when the Board's proposed report is issued, unless the land subsequently is zoned for nonresidential use.
In preparing its order, the PSC must evaluate projected costs and benefits in terms of the long-term production capacity and long-term needs for transmission. The order must ensure that the designation of a wind zone does not represent an unreasonable threat to the public convenience, health, and safety, and that any adverse impacts on private property values are minimal. Additionally, the PSC must consider all of the following factors pursuant to the findings of the Board:
-- Average annual wind velocity levels in the region.
-- Availability of land in the region that may be used by wind energy conversion systems.
-- Existing wind energy conversion systems in the region.
-- Potential for megawatt output of combined wind energy conversion systems in the region.
-- Other necessary and appropriate factors as to which findings are required by the PSC.
In conjunction with the issuance of its order, the PSC must submit to the Legislature a report on the effect that setback requirements and noise limitations under local zoning or other ordinances may have on wind energy development in wind resource zones. The report must include any recommendations the PSC has for legislation addressing those issues. Before preparing the report, the PSC must conduct hearings in various areas of the State to receive public comment on it.
Expedited Siting Certificates. To facilitate transmission of electricity generated by wind energy conversion systems located in wind energy resource zones, the PSC may issue an expedited siting certificate to an electric utility, affiliated transmission company, or independent transmission company.
An electric utility, affiliated transmission company, or independent transmission company may apply to the PSC for an expedited siting certificate. An applicant may withdraw an application at any time. The PSC must grant or deny an expedited siting certificate within 180 days.
Before applying for expedited siting of a proposed transmission line, an electric utility, affiliated transmission company, or independent transmission company must receive any required approvals from the applicable RTO for the proposed line. ("Transmission line" means all structures, equipment, and real property necessary to transfer electricity at system bulk supply voltage of at least 100 kilovolts.)
Sixty days before seeking approval from the applicable RTO for a transmission line, an electric utility or transmission company must give the PSC written notice that it will seek such approval. The PSC must represent the State's interests in all proceedings before the applicable RTO for which the PSC receives notice.
An application for an expedited siting certificate must contain all of the following:
-- Evidence that the proposed transmission line received any required approvals from the applicable RTO.
-- The planned date for beginning construction of the proposed line.
-- A detailed description of the proposed line, its route, and its expected configuration and use.
-- Information addressing potential effects of the proposed line on public health and safety.
-- Information indicating that the proposed line will comply with all applicable State and Federal environmental standards, laws, and rules.
-- A description and evaluation of at least one alternate transmission line route and a statement of why the proposed route was selected.
-- Other information the PSC reasonably requires by rule.
Upon applying for a certificate, an electric utility or transmission company must give public notice, in the manner and form the PSC prescribes, of an opportunity to comment on and participate in a contested case with respect to the application. Notice must be published in a newspaper of general circulation in the relevant wind energy resource zone within a reasonable time period after an application is given to the PSC, and must be sent to each affected municipality and each affected landowner on whose property a portion of the proposed line will be constructed. The notice must be written in plain, nontechnical, and easily understood terms, and must contain a title that includes the name of the utility or transmission company and the words "Notice of Intent to Construct a Transmission Line in a Wind Energy Resource Zone".
The PSC must conduct a proceeding on the application as a contested case under the APA. Upon receiving an application, each affected municipality and landowner must be granted full intervener status as of right in Commission proceedings concerning the proposed line.
The Commission must grant an expedited siting certificate if it determines that all of the following requirements are met:
-- The proposed line will facilitate transmission of electricity generated by wind energy conversion systems located in a wind energy resource zone.
-- The proposed line has received Federal approval.
-- The proposed line does not represent an unreasonable threat to the public convenience, health, and safety.
-- The proposed line will be of appropriate capability to enable the wind potential of the wind energy resource zone to be realized.
-- The proposed or alternate route to be authorized by the certificate is feasible and reasonable.
If the PSC grants a certificate, it will take precedence over a conflicting local ordinance, law, rule, regulation, policy, or practice that prohibits or regulates the location or construction of a transmission line. A zoning ordinance or limitation imposed after an electric utility, affiliated transmission company, or independent transmission company files for a certificate will not limit or impair the line's construction, operation, or maintenance.
In an eminent domain or other related proceeding arising out of or related to a transmission line for which expedited siting authority is issued, a certificate issued under the Act will be conclusive and binding as to the public convenience and necessity for that transmission line and its compatibility with the public health and safety or any zoning or land use requirements in effect when the application was filed.
PSC Wind Energy Report
By the first Monday of March each year, the PSC must make to the Governor and the Legislature a report summarizing the impact of establishing wind energy resource zones, expedited transmission line siting applications, estimates for future wind generation within the zones, and recommendations for program enhancements or expansion.
Transmission Line Construction
Part 4 specifies that it does not prohibit an electric utility, affiliated transmission company, or independent transmission company from constructing a transmission line without obtaining an expediting siting certificate.
PSC Authority; Scope of Part 4
A PSC order relating to any matter provided for under Part 4 is subject to review as provided in Section 26 of Public Act 300 of 1909 (which governs railroads). (That section pertains to judicial appeals of Commission orders fixing rates, fares, charges, classifications, joint rates, regulations, practices, and services.)
In administering Part 4, the PSC has only those powers and duties granted to it under that part. Part 4 does not confer the power of eminent domain.
Part 5: Net Metering
The PSC must establish a statewide net metering program by order issued within 180 days after the Act's effective date. By that date, the PSC must promulgate rules regarding any time limits on the submission of net metering applications or inspections of net metering equipment and any other matters the Commission considers necessary to implement Part 5. Any rules adopted regarding time limits for approval of parallel operation must recognize reliability and safety complications, including those arising from equipment saturation, use of multiple technologies, and proximity to synchronous motor loads. The program must apply to all electric utilities and AESs in Michigan. Except as otherwise provided, customers of any class are eligible to interconnect eligible electric generators with the customer's local electric utility and operate them in parallel with the distribution system. The program must be designed for a period of at least 10 years and must limit each customer to generation capacity designed to meet only the customer's electric needs. The PSC may waive the application, interconnection, and installation requirements of Part 5 for customers participating in the net metering program under the Commission's March 29, 2005, order in Case No. U-14346 (in which the PSC approved a proposed voluntary, statewide net metering program).
(As used in Part 5, "electric utility" means any person or entity whose rates are regulated by the PSC for the purpose of selling electricity to Michigan retail customers.)
A utility or AES is not required to allow for net metering that is greater than 1% of its in-State peak load for the preceding calendar year. The utility or supplier must notify the PSC if its program reaches the 1% limit. That limit must be allocated as follows:
-- A maximum of 0.5% for customers with a system capable of generating 20 kilowatts or less.
-- A maximum of 0.25% for customers with a system capable of generating more than 20 kilowatts but not more than 150 kilowatts.
-- A maximum of 0.25% for customers with a system capable of generating more than 150 kilowatts.
Selections of customers for participation in the net metering program must be based on the order in which the utility or AES receives applications for participation. A utility or AES may not refuse to provide or discontinue electric service to a customer solely for the reason that the customer participates in the program.
The program must include all of the following:
-- Statewide uniform interconnection requirements (designed to protect utility workers, equipment, and the general public) for all eligible electric generators.
-- Net metering equipment and its installation that meet all current local and State electric and construction code requirements.
-- A uniform application form and process to be used by all electric utilities and AESs in Michigan.
Any equipment that is certified by a nationally recognized testing laboratory to IEEE 1547.1 testing standards and in compliance with UL 1741 scope 1.1A, effective May 7, 2007, and installed in compliance with Part 5 is considered to be eligible equipment. Within the time provided by the PSC rules and consistent with good utility practice and protection of utility workers, electric utility equipment, and the general public, a utility may study, confirm, and ensure that an eligible generator installation at the customer's site meets the IEEE 1547 anti-islanding requirements. Utility testing and approval of the interconnection and execution of a parallel operating agreement must be completed before the operation of the equipment parallel with the utility's distribution system.
Customers who are served by an AES must submit a copy of the application to the electric utility for the customer's service area.
Net metering customers with a system capable of generating 20 kilowatts or less qualify for true net metering. Net metering customers with a system capable of generating more than 20 kilowatts qualify for modified net metering.
Each utility and AES must maintain records of all applications and up-to-date records of all active eligible electric generators located within their service areas.
A utility or AES may charge a maximum fee of $100 to process an application for net metering. A customer with a system capable of generating more than 20 kilowatts must pay all interconnection costs. A customer with a system capable of generating more than 150 kilowatts must pay standby costs. The PSC must recognize the reasonable cost for each utility and AES to operate a net metering program. For an electric utility with at least 1.0 million Michigan base distribution customers, the PSC must include in its nonfuel base rates all costs of meeting all program requirements, except that all energy costs must be recovered through the utility's PSCR mechanism. For a utility with fewer than 1.0 million base distribution customers in Michigan, the PSC must allow it to recover all energy costs of the program through the PSCR mechanism, and must develop a cost recovery mechanism for that utility to recover contemporaneously all other costs of meeting the program requirements.
The program's interconnection requirements must require all eligible electric generators, AESs, and electric utilities to comply with all applicable Federal, State, and local laws, rules, or regulations, and any national standards as determined by the PSC.
Electric meters must be used to determine the amount of the customer's energy usage in each billing period, net of any excess energy the customer's generator delivers to the utility distribution system during the same billing period. For a customer with a system capable of generating more than 20 kilowatts, the utility must install and use a generation meter and a meter or meters capable of measuring the flow of energy in both directions. A customer with a system capable of generating more than 150 kilowatts must pay the costs of installing any new meters.
An electric utility serving more than 1.0 million Michigan customers must provide a meter or meters to customers participating in the net metering program at cost. Only the incremental cost above that for meters provided by the utility to similarly situated nongenerating customers must be paid by the eligible customer.
If the quantity of electricity generated and delivered to the utility distribution system by an eligible electric generator during a billing period exceeds the quantity of electricity supplied from the utility or AES during the billing period, the eligible customer must be credited by the supplier of generation service for the excess kilowatt hours generated during the billing period. The credit must appear on the bill for the following billing period and must be limited to the total power supply charges on that bill. Any excess kilowatt hours not used to offset generation charges in the next billing period must be carried forward to subsequent billing periods. Notwithstanding any law or regulation, net metering customers may not receive credits for utility transmission or distribution charges.
The credit per kilowatt hour for kilowatt hours delivered into the utility's distribution system must be either 1) the utility's or AES's power supply component of the full retail rate during the billing period or time-of-use pricing period; or 2) the monthly average real-time locational marginal price for energy at the commercial pricing node within the utility's distribution service territory, or for net metering customers on a time-based rate schedule, the monthly average real-time locational marginal price for energy at the commercial pricing node within the utility's distribution service territory during the time-of-use pricing period.
An eligible electric generator will own any renewable energy credits granted for electricity generated under the net metering program.
Upon a complaint or on the PSC's own motion, if the Commission finds, after notice and hearing, that an electric utility has not complied with a provision or order issued under Part 5, it must order remedies and penalties as necessary to make whole a customer or other person who has suffered damages as a result of the violation.
Part 6: Miscellaneous Commission Provisions
Within 60 days after the effective date of the Act, the PSC must issue a temporary order implementing it, including formats of renewable energy plans for various categories of electric providers and guidelines for RFPs under the Act.
Within one year after the Act's effective date, the PSC must promulgate rules to implement the Act pursuant to the APA. Upon promulgation of the rules, the temporary order will be rescinded.
Any interested party may intervene in a contested case proceeding under the Act as provided in general PSC rules.
The PSC and a provider must handle confidential business information under the Act in a manner consistent with State law and general Commission rules.
The Act does not limit any Commission authority otherwise provided by law.
As provided in Section 5 of 1846 RS 1, the Act is severable. (That section provides that, if any portion of an act or its application to any person or circumstances is found invalid by a court, the invalidity does not affect the remaining portions or applications of the act that can be given effect without the invalid portion or applications, provided the court does not determine those portions to be inoperable.)
House Bill 5524
General PSC Law Revisions
PSC Organization & Funding. The bill states that, except as otherwise provided, the PSC is subject to Executive Reorganization Order No. 2003-1 (MCL 445.2011). (That order renamed the Department of Consumer and Industry Services the "Department of Labor and Economic Growth", which includes the PSC, and transferred various bureaus, commissions, committees, programs, and authorities among several departments.)
Funding for the PSC is as provided under Public Act 299 of 1972 (which governs the costs of regulating public utilities) and as otherwise provided by law.
The bill specifies that the PSC is an autonomous entity within the Department of Labor and Economic Growth (now DELEG). The PSC retains the statutory authority, powers, duties, and functions, including personnel, property, budgeting, records, procurement, and other management-related functions. The Department must provide support and coordinated services as requested by the Commission and must be reimbursed for that service as provided in the bill.
The PSC chairperson must be appointed as provided under Section 2 (which requires the Governor to designate one PSC member to serve as the chairperson). The bill specifies that none of these provisions may be construed to supersede the transfers of authority made under the following Executive Orders:
-- Executive Reorganization Order No. 2001-1 (MCL 18.41) (which created the Department of Information Technology and transferred to it certain functions assigned previously to the DMB).
-- Executive Reorganization Order No. 2002-13 (MCL 18.321) (which transferred to the DMB responsibilities pertaining to the planning, management and operation, capital renewal, and acquisition of buildings and facilities of Executive branch agencies).
-- Executive Reorganization Order No. 2005-1 (MCL 445.2021) (which created the State Office of Administrative Hearings and Rules within DELEG).
-- Executive Reorganization Order No. 2007-21 (MCL 18.45) (which transferred the Board of Ethics, the State Officers Compensation Commission, and the Civil Service Commission to the DMB).
-- Executive Reorganization Order No. 2007-22 (MCL 18.46) (which transferred to the State Budget Director the powers and duties of internal auditors of principal departments, and the powers and duties of principal departments to appoint and supervise internal auditors).
-- Executive Reorganization Order No. 2007-23 (MCL 18.47) (which transferred powers and duties pertaining to accounting functions to the Office of the State Budget Director).
Utility Rate Increase. Previously, when a gas or electric utility sought a finding or order to increase its rates and charges or to alter, change, or amend any rate or rate schedules, the effect of which would be to increase the cost of services to its customers, notice had to be given within the service area to be affected. The bill, instead, prohibits a gas or electric utility from increasing its rates and charges or altering, changing, or amending any rate or rate schedules, the effect of which will be to increase the cost of services, without first receiving PSC approval as provided in the bill.
The bill retained a requirement that the utility place in evidence facts relied upon to support its petition or application to increase rates and charges, or to alter, change, or amend any rate or rate schedules.
Previously, after giving notice to the interested parties within the service area to be affected and affording interested parties a reasonable opportunity for a full and complete hearing, the PSC, after submission of all proofs by an interested party, could in its discretion and upon written motion by the utility, make a finding and enter an order granting partial and immediate relief. A finding or order could not be authorized or approved ex parte (without notice to or the appearance of other parties), or until the PSC's technical staff had made an investigation and report. The bill deleted these provisions.
Instead, the PSC must require notice to be given to all interested parties within the affected service area, and all interested parties must have a reasonable opportunity for a full and complete hearing. A utility may use projected costs and revenue for a future consecutive 12-month period in developing its requested rates and charges. The PSC must notify the utility within 30 days of the filing whether its application or petition is complete. A petition or application must be considered complete if it complies with the rate application filing forms and instructions adopted as prescribed in the bill. A petition or application pending before the PSC before the adoption of filing forms and instructions must be evaluated based upon the filing requirements in effect at that time.
The bill requires the PSC, if the application is not complete, to notify the utility of all information necessary to make that filing complete. If the PSC does not notify the utility within 30 days, the application must be considered complete. If the PSC does not issue 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. For a petition or application pending before the PSC before the bill's effective date, the 180-day period commenced on that date. If the utility uses projected costs and revenue for a future period in developing its requested rates and charges, it may not implement the equal percentage increases or decreases before the calendar date corresponding to the start of the projected 12-month period.
The bill allows the PSC, for good cause, to issue a temporary order preventing or delaying a utility from implementing its proposed rates or charges. If a utility implements increased rates or charges before the PSC issues a final order, it must refund to customers, with interest, any portion of the total revenue collected through application of the equal percentage increase that exceeds the total that would have been produced by the rates or charges ordered subsequently by the Commission in its final order. The PSC must allocate any required refund 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 must equal 5% plus the London Interbank Offered Rate (LIBOR) for the appropriate time period. For any portion of the refund that, excluding interest, exceeds 25% of the annual revenue increase awarded by the PSC in its final order, the interest rate must be the authorized rate of return on the common stock of the utility during the appropriate period. Any refund or interest awarded may not be included in any application for a rate increase by a utility. Nothing in these provisions impairs the PSC's ability to issue a show cause order as part of its rate-making authority.
Previously, the Act required the PSC to adopt rules and procedures for the filing, investigation, and hearing of petitions or applications to increase or decrease utility rates and charges as it found necessary or appropriate to enable it to reach a final decision with respect to petitions or applications within nine months from their filing. The bill retained this provision but increased the time period to 12 months, and refers to complete petitions and applications.
The bill deleted a requirement that the PSC give priority to a case and take other necessary or appropriate action to expedite a final decision if it did not reach a final decision within the nine-month period.
Previously, if the PSC failed to reach a final decision with respect to a petition or application to increase or decrease rates within the nine-month period following the filing, within 15 days it had to submit a written report to the Governor, the President of the Senate, and the Speaker of the House stating the reasons a decision was not reached by the deadline and the actions being taken to expedite the decision. Upon reaching a final decision, the Commission had to submit a further report providing full details with respect to the conduct of the case. The bill deleted these provisions.
Under the bill, except as otherwise provided, if the PSC fails to reach a final decision with respect to a completed petition or application within the 12-month period, the petition or application is considered approved. If a utility makes any significant amendment to its filing, the PSC will have an additional 12 months from the date of the amendment to reach a final decision. If the utility files for an extension, the PSC must extend the 12-month period by the amount of additional time requested.
The bill prohibits a utility from filing 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. Also, a utility may not file a new general rate case application until the PSC has issued a final order on a prior general rate case or until the rates are approved without a final decision.
Gas Utility Transportation Schedules & Contracts. The bill requires the PSC, if requested by a gas utility, to establish load retention transportation rate schedules or approve gas transportation contracts as required for the purpose of retaining industrial or commercial customers whose individual annual transportation volumes exceed 500,000 decatherms on the gas utility's system. The PSC must 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, can obtain the alternative fuel or gas transportation from an alternative source at a price that would cause the customer to cease using the gas utility's system, and the customer, as a result of its use of the system and receipt of transportation service, makes a significant contribution to the utility's fixed costs.
The PSC must 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 not 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.
Standard Forms & Instructions. Within 90 days of the bill's effective date, the PSC must adopt standard rate application filing forms and instructions for use in all general rate cases filed by utilities whose rates are regulated by the PSC (referred to below as rate-regulated utilities). For a cooperative electric utility whose rates are regulated by the Commission, in addition to rate applications filed under the general rate case provisions, the PSC must continue to allow for rate filings based on the cooperative's times interest earned ratio. In its discretion, the PSC may modify the adopted standard rate application forms and instructions.
Merchant Plant Renewable Energy Contracts. Under the bill, if a merchant plant, on or before January 1, 2008, entered into a contract with an initial term of at least 20 years to sell electricity to a rate-regulated electric utility with at least 1.0 million Michigan retail customers, and if, before that date, the plant generated electricity under the contract, in whole or in part, from wood or solid wood waste, then the plant must recover the amount, if any, by which its reasonably and prudently incurred actual fuel and variable operation and maintenance costs exceed the amount that the plant is paid under the contract for those costs. This provision does not apply to landfill gas plants, hydro plants, or municipal solid waste plants, or to merchant plants engaged in litigation against an electric utility seeking higher payments for power delivered pursuant to contract.
The total aggregate additional amounts recoverable by merchant plants under those provisions in excess of the amounts paid under the contracts may not exceed $1.0 million per month for each affected electric utility. The PSC must review that limit upon petition of the merchant plants filed not more than once per year, and may adjust the limit 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 plants are paid under the contract by more than $1.0 million per month. The annual amount of the adjustments may not exceed a rate equal to the United States Consumer Price Index. The PSC may not make an adjustment unless each affected merchant plant files a petition. 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 plants are paid under the contract by more than $1.0 million per month, the PSC must allocate the additional $1.0 million per month payment among the eligible plants based upon the relationship of excess costs among them. The $1.0 million limit, as adjusted, does not apply with respect 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 the bill's effective date. The limit also does not apply to eligible merchant plants 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.
Upon a merchant plant's petition, the PSC must issue orders to permit this recovery. The merchant plant may not be required to alter or amend the existing contract with the electric utility in order to obtain the authorized recovery. The PSC must permit or require the rate-regulated utility to recovery from its ratepayers fuel and variable operation and maintenance costs that the utility is required to pay to the merchant plant as reasonably and prudently incurred costs.
Jurisdictional Regulated Utility Transactions. Under the bill, a person may not acquire, control, or merge, directly or indirectly, in whole or in part, with a jurisdictional regulated utility, nor may a jurisdictional regulated utility sell, assign, transfer, or encumber its assets to another person without first applying to and receiving the approval of the PSC.
("Jurisdictional regulated utility" means a utility whose rates are regulated by the PSC. The term does not include a telecommunication provider or a motor carrier.)
After notice and hearing, the PSC must issue an order stating what constitutes acquisition, transfer of control, merger activities, or encumbrance of assets that are subject to these restrictions. These provisions do not apply to the encumbrance, assignment, acquisition, or transfer of assets that are encumbered, assigned, acquired, transferred, or sold in the normal course of business or to the issuance of securities or other financing transactions not directly or indirectly involved in an acquisition, merger, encumbrance, or transfer of control that is governed by these provisions.
The PSC must promulgate rules creating procedures for the required application process. The application must include all of the following:
-- A concise summary of the terms and conditions of the proposed acquisition, transfer, merger, or encumbrance.
-- Copies of the material acquisition, transfer, merger, or encumbrance documents, if available.
-- A summary of the projected impacts of the transaction on rates and electric service in Michigan.
-- Pro forma financial statements that are relevant to the transaction.
-- Copies of the parties' public filings with other State or Federal regulatory agencies regarding the same transaction, including any regulatory orders issued.
Within 60 days from the date an application is filed, interested parties, including the Attorney General, may file with the PSC comments on the proposed transaction. After notice and hearing and within 180 days from the filing date, the PSC must issue an order approving or rejecting the proposed transaction.
All parties to an acquisition, transfer, merger, or encumbrance subject to these provisions must give the PSC and the Attorney General access to all books, records, accounts, documents, and any other data and information the PSC considers necessary to assess effectively the impact of the proposed transaction.
Among other factors, in evaluating whether to approve a proposed transaction, the PSC must consider whether it would do any of the following:
-- Have an adverse impact on the rates of the affected customers.
-- Have an adverse impact on the provision of safe, reliable, and adequate energy service in Michigan.
-- Result in the subsidization of a nonregulated activity of the new entity through the rates paid by the customers of the jurisdictional regulated utility.
-- Significantly impair the utility's ability to raise necessary capital or to maintain a reasonable capital structure.
The PSC also must consider whether the action is otherwise inconsistent with public policy and interest.
In approving a proposed acquisition, transfer, merger, or encumbrance, the PSC may impose reasonable terms and conditions on the transaction to protect the jurisdictional regulated utility, including the division and allocation of its assets, or to protect its customers. The utility may reject the terms and conditions imposed by the PSC and not proceed with the transaction.
Nonpublic information and materials submitted by a jurisdictional regulated utility that it clearly designates as confidential are exempt from the Freedom of Information Act. The PSC must issue orders as necessary to protect information designated confidential.
Nothing in these provisions alters the authority of the Attorney General to enforce Federal and State antitrust laws.
Certificate of Necessity. Under the bill, if an electric utility proposes to construct an electric generation facility, purchase or make a significant investment in an existing electric generation facility, or enter into a power purchase agreement for the purchase of electric capacity for a period of at least six years, the electric utility may submit an application to the PSC seeking a certificate of necessity (CON) for that construction, investment, or purchase if it costs at least $500.0 million and a portion of the costs would be allocable to retail customers in Michigan. A significant investment in an electric generation facility includes a group of investments reasonably planned to be made over a multiple-year period of up to six years for a singular purpose, such as increasing the capacity of an existing generation plant. The PSC may not issue a CON for any environmental upgrades to existing electric generation facilities or for a renewable energy system. ("Renewable energy system" means that term as defined in the Clean, Renewable, and Efficient Energy Act.)
The PSC may implement separate review criteria and approval standards for electric utilities with fewer than 1.0 million retail customers that seek a CON for projects costing less than $500.0 million.
An electric utility applying for a certificate of necessity may request one or more of the following:
-- A CON that the power to be supplied as a result of the proposed construction, investment, or purchase is needed.
-- A CON that the size, fuel type, and other design characteristics of the existing or proposed facility or the terms of the power purchase agreement represent the most reasonable and prudent means of meeting that power need.
-- A CON that the price specified in the power purchase agreement will be recovered in rates from the electric utility's customers.
-- A CON that the estimated purchase or capital costs of the existing or proposed electric generation facility, including the costs of siting and licensing a new facility and the estimated cost of power from it, will be recoverable in rates from the electric utility's customers, subject to requirements that costs be reasonable.
Within 270 days after an application is filed, the PSC must issue an order granting or denying the requested CON. The PSC must hold a contested case hearing on the application, and allow intervention by interested people. Reasonable discovery must be permitted before and during the hearing in order to assist parties and interested people in obtaining evidence concerning the application, including the reasonableness and prudence of the construction, investment, or purchase for which the CON has been requested. The PSC must grant the request if it determines all of the following:
-- That the electric utility has demonstrated a need for the power that would be supplied by the existing or proposed facility or pursuant to the proposed power purchase agreement through its approved integrated resource plan that complies with certain provisions (described below).
-- The information supplied indicates that the existing or proposed facility will comply with all applicable State and Federal environmental standards, laws, and rules.
-- The existing or proposed facility or 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 and electric transmission efficiencies.
-- To the extent practicable, the construction or investment in a new or existing facility in Michigan is completed using a workforce composed of Michigan residents, as determined by the PSC (except with regard to a facility located in a county bordering another state).
The PSC also must determine that the estimated cost of power from the existing or proposed facility or the price of power specified in the proposed purchase agreement 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 competitive solicitation. An affiliate of a utility that serves customers in Michigan and at least one other state may participate in the competitive bidding to provide engineering, procurement, and construction services to that utility for a covered project.
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 PSC to issue an order granting or denying a CON.
The PSC may consider any other costs or information related to the costs associated with the power that would be supplied by the existing or proposed facility or pursuant to the proposed purchase agreement or alternatives to the proposal raised by intervening parties.
In a certificate of necessity, the PSC must specify the costs approved for the construction of or significant investment in the facility, the price approved for the purchase of the existing facility, or the price approved for the purchase of power pursuant to the terms of the power purchase agreement.
The utility must file annually, or more frequently if required by the PSC, reports to the PSC regarding the status of any project for which a CON has been granted, including an update concerning the cost and schedule of the project.
If the PSC denies any of the relief requested by an electric utility, the utility may withdraw its application or proceed with the proposed construction, purchase, investment, or power purchase agreement without a CON and the assurances granted under the bill.
Once the electric generation facility or power purchase agreement is considered used and useful or as otherwise provided (for construction work in progress), the PSC must include in a utility's retail rates all reasonable and prudent costs for a facility or agreement for which a CON has been granted. The PSC may not disallow recovery of costs a utility incurred in constructing, investing in, or purchasing a generation facility or in purchasing power pursuant to an agreement for which a CON has been granted, if the costs do not exceed those approved by the PSC. Once the facility or agreement is considered used and useful or as otherwise provided, the PSC must include in the utility's retail rates costs actually incurred by the utility that exceed the approved costs only if the PSC finds that the additional costs are reasonable and prudent. If the actual incurred costs exceed the approved costs, the 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, or power purchase agreement that exceeds 110% of the approved cost is presumed to have been incurred due to a lack of prudence. The PSC may include any or all of the portion of the cost in excess of 110% of the approved cost if it finds by a preponderance of the evidence that the costs were incurred prudently.
Within 90 days of the bill's effective date, the PSC must adopt standard application filing forms and instructions for use in all requests for a CON. In its discretion, the PSC may modify the adopted forms and instructions.
The PSC must establish standards for an integrated resource plan that a utility requesting a CON must file. An integrated resource plan must include all of the following:
-- A long-term forecast of the utility's load growth under various reasonable scenarios.
-- The type of generation technology proposed for the facility and its proposed capacity, including projected fuel and regulatory costs under various reasonable scenarios.
-- Projected energy and capacity purchased or produced by the utility pursuant to any renewable portfolio standard (RPS).
-- Projected energy efficiency program savings under any energy efficiency program requirements and the projected costs for that program.
-- Projected load management and demand response savings for the utility and the projected costs for those programs.
-- Electric transmission options for the electric utility.
An integrated resource plan also must include an analysis of the availability and costs of other electric resources that could defer, displace, or partially displace the proposed facility or agreement, including additional renewable energy, energy efficiency programs, load management, and demand response, beyond those amounts included in projected RPS purchases, projected energy efficiency program savings, and projected load management and demand response savings.
The PSC must allow financing interest cost recovery in a utility's base rates on construction work in progress for certified capital improvements before the assets are considered used and useful. Regardless of whether the PSC authorizes base rate treatment for construction work in progress financing interest expense, a utility must be allowed to recognize, accrue, and defer the allowance for funds used during construction related to equity capital.
Electric Rates Adoption & Approval
Except as provided below for utilities with fewer than 1.0 million customers, the following provisions apply only to an electric utility with at least 1.0 million Michigan retail customers.
Cost-of-Service Rates. Beginning January 1, 2009, the bill requires the PSC to phase in electric rates equal to the cost of providing service to each customer class over a period of five years from the bill's effective date. The cost of providing service to each customer class must be based on the allocation of production-related and transmission costs to each customer class based on using the 50-25-25 method of cost allocation. The PSC may modify this method to ensure that rates are equal to the cost of service if that method does not result in a greater amount of production-related and transmission costs allocated to primary customers.
The PSC must ensure that the impact on residential and industrial metal melting rates due to the cost-of-service requirement is not more than 2.5% per year. If the PSC determines that the rate impact on industrial metal melting customers will exceed this limit, it may phase in cost-based rates for that class over a period of more than five years.
Low-Income & Senior Citizen Customers. The bill allows the PSC, notwithstanding any other provision of the Act, to establish eligible low-income customer or eligible senior citizen customer rates. Upon filing a rate increase request, a utility must include proposed eligible low-income and senior citizen rates and a method to allocate the revenue shortfall attributed to the implementation of those rates upon all customer classes.
("Eligible low-income customer" and "eligible senior citizen customer" mean those terms as defined in Section 10t. Under that section, "eligible low-income customer" means a customer whose household income does not exceed 150% of the poverty level, as published by the U.S. Department of Health and Human Services, or who receives assistance from a State emergency relief program, food stamps, or Medicaid. "Eligible senior citizen customer" means a utility or supplier customer who is at least 65 years old and who advises the utility of his or her eligibility.)
Educational Institutions. The bill requires the PSC, notwithstanding other provisions, to 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 them. Within 90 days after the bill takes effect, regulated electric utilities must file with the PSC tariffs to ensure that those institutions are charged electric rates as provided in the bill.
Utilities with Fewer than 1.0 Million Customers. Beginning January 1, 2009, the PSC must approve rates equal to the cost of providing service to customers of electric utilities serving fewer than 1.0 million retail customers in Michigan. The rates must be approved by the PSC in each utility's first general rate case filed after passage of the bill. If, in the Commission's judgment, imposing cost-of-service rates on customers would have a material impact, the PSC may approve an order that implements those rates over a suitable number of years. The PSC must ensure that any impact on rates due to the cost-of-service requirement is not more than 2.5% per year.
Customer Choice & Electricity Reliability Act Revisions
Purposes. Sections 10 through 10bb of the PSC law are known as the "Customer Choice and Electricity Reliability Act". Section 10 prescribes the purposes of the Act. The bill added to those purposes the maintenance, fostering, and encouragement of robust, reliable, and economic generation, distribution, and transmission systems to give Michigan's electric suppliers and generators an opportunity to gain access to regional sources of generation and wholesale power markets and to ensure a reliable supply of electricity in this State.
The bill deleted a provision under which the statement of purposes did not apply after December 31, 2003.
PSC Orders; AES Service. The Act requires the PSC to issue orders establishing the rates, terms, and conditions of service that allow all retail customers of an electric utility or provider to choose an AES.
The bill defines "customer", as used in these provisions, as the building or facilities serviced through a single existing electric billing meter. The term does not mean the person, corporation, partnership, association, governmental body, or other entity owning or having possession of the building or facilities.
Under the bill, the PSC orders must provide that not more than 10% of an electric utility's average weather-adjusted retail sales for the preceding calendar year may take service from an AES at any time.
The bill also requires the orders to set forth procedures necessary to administer and allocate the amount of load that AESs will be allowed to serve, through the use of annual energy allotments awarded on a calendar-year basis. The orders must provide, among other things, that existing customers taking electric service from an AES at a facility on the bill's effective date must be given an allocated annual energy allotment for that service at that facility, and that customers seeking to expand usage at a facility served through an AES will be given next priority, with the remaining available load, if any, allocated on a first-come, first-served basis. The procedures also must provide how customer facilities will be defined for the purpose of assigning the energy allotments. The PSC may not allocate additional allotments at any time when the total allotments for the utility's distribution service territory are greater than 10% of the utility's weather-adjusted retail sales in the calendar year preceding the allocation date. If a utility's sales are less in a subsequent year or if the energy usage of an AES customer exceeds its annual energy allotment for that facility, that customer may not be forced to purchase electricity from a utility, but may purchase electricity from an AES for that facility during that calendar year.
In addition, under the bill, notwithstanding any other provision, the orders must provide that customers seeking to expand usage at a facility that has been served continuously through an AES since April 1, 2008, must be permitted to purchase electricity from an AES for both the existing and any expanded load at that facility, as well as any new facility constructed after the bill's effective date that is similar in nature if the customer owns more than 50% of the new facility.
Also, notwithstanding any other provision, the orders must provide that any customer operating an iron ore mining and/or processing facility located in the Upper Peninsula must be permitted to purchase all or any portion of its electricity from an AES, regardless of whether the sales exceed 10% of the serving electric utility's average weather-adjusted retail sales.
Under the bill, a customer electing to receive service from an AES subsequently may notify the electric utility of the customer's desire to receive standard tariff service from that utility. The bill ratifies the procedures in place for each utility as of January 1, 2008, that set forth the terms under which an AES customer may return to full service from the utility. The terms remain in effect and may be amended by the PSC as needed. If a utility did not have the procedures in place as of that date, the PSC must adopt them.
(The bill defines "standard tariff service", for each regulated electric utility, as the retail rates, terms, and conditions of service approved by the PSC for service to customers who do not elect to receive generation service from AESs.)
The bill deleted a requirement that the PSC orders provide for full recovery of a utility's net stranded costs and implementation costs as determined by the PSC.
Stranded Costs & Securitization. The Act required the PSC, after a contested case proceeding, to issue annually an order approving for each electric utility a true-up adjustment to reconcile any overcollections or undercollections of the preceding 12 months to ensure the recovery of all amounts of net stranded costs. The PSC had to review the utility's stranded cost recovery charges and securitization charges implemented for the preceding 12 months, and adjust the stranded cost recovery charge to allow the netting of stranded costs.
The PSC had to consider the reasonableness and appropriateness of specified methods to determine net stranded costs.
The true-up adjustment could not result in a modification to the securitization charge. The PSC could not adjust or change in any manner securitization charges authorized in a financing order issued to allow a utility to recover qualified costs as a result of its review and any action taken under an order issued following the true-up adjustment.
After the date established under Section 10d(2) (i.e., the earlier of December 31, 2013, or the PSC's determination that a utility met a market test and had completed required transmission expansion), the rates for retail customers that remained with or left and later returned to the incumbent electric utility had to be determined in the same manner as the rates were determined before June 5, 2000.
The bill deleted all of these provisions.
Recovery of Costs. Under the bill, the PSC must authorize rates that will ensure that an electric utility that offered retail open access service from 2002 through the bill's effective date fully recovers its restructuring costs and any associated accrued regulatory assets. This includes implementation costs, stranded costs, and other costs authorized under existing provisions, that the PSC has authorized for recovery in orders issued before the bill's effective date. The PSC must approve surcharges that will ensure full recovery of all such costs within five years after the bill's effective date.
Standby Generation Service. Under the Act, an electric utility, with PSC oversight, is obligated to provide standby generation service for open access load on a best efforts basis until December 31, 2001, or the date established under Section 10d(2), whichever is later. Until the date established under that section, standby generation service must continue to be provided to nonopen access customers under regulated tariffs. The bill refers to Section 10d(2) as it existed before the bill's effective date.
Established Rates. The Act required the PSC to establish residential rates for each utility with at least 1.0 million customers in Michigan as of May 1, 2000, that resulted in a 5% rate reduction from the rates that were authorized or in effect on that date. Those rates became effective on June 5, 2000, and remained in effect until December 31, 2003. All other retail rates of a utility with at least 1.0 million customers authorized or in effect on May 1, 2000, remained in effect until December 31, 2003.
Effective on and after December 31, 2003, the Act prohibited rates for a utility with more than 1.0 million Michigan customers from being increased until the earlier of December 31, 2013, or until the PSC determined that the utility met a specified market test and had completed required transmission expansion. The rates for commercial or manufacturing customers of the applicable utilities with annual peak demands of less than 15 kilowatts could not be increased before January 1, 2005. The Act prohibited cost shifting from customers with capped rates to customers without capped rates as a result of this section. The Act also prohibited residential rates from being increased before January 1, 2006, above the established rates.
The bill deleted these provisions, as well as related provisions concerning securitization savings.
Service Quality & Reliability Standards. The Act requires the PSC to adopt generally applicable service quality and reliability standards for the transmission and distribution systems of electric utilities and other entities subject to its jurisdiction, including standards for service outages, distribution facility upgrades, repairs and maintenance, telephone service, billing service, operational reliability, and public and worker safety. The bill requires the PSC also to adopt standards for generation systems.
Under the Act, each jurisdictional utility or entity must file with the PSC an annual report 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 standards during the previous year. The annual reports must contain data required by the PSC. Under the bill, the required data include the estimated cost of achieving improvements in the jurisdictional utility's or entity's performance with respect to the standards.
Previously, the PSC had to analyze the data to determine whether the jurisdictional entities were operating and maintaining their systems properly, assess the impact of deregulation on reliability, and take corrective action if needed. Under the bill, the Commission does not have to assess the impact of deregulation on reliability.
Quality & Efficiency Report. The bill requires the PSC, by September 1, 2009, to submit a report to the Governor and the Legislature. In preparing the report, the Commission must review and consider relevant existing customer surveys and examine what other states have done. The report must include all of the following:
-- An assessment of the major types of end-use customer power quality disturbances, including voltage sags, overvoltages, oscillatory transients, voltage swells, distortion, power frequency variations, and interruptions, caused by both the distribution and transmission systems within Michigan.
-- An assessment of utility power plant generating cost efficiency, including operational efficiency, economic generating cost efficiency, and schedules for planned and unplanned outages.
-- Current efforts employed by the PSC to monitor or enforce standards pertaining to end-use customer power quality disturbances and utility power plant generating cost efficiency through current practice, statute, policy, or rule.
-- Recommendations for use of common characteristics, measures, and indices to monitor power quality disturbances and power plant generating cost efficiency, such as expert customer service assessments, frequency of disturbance occurrence, duration of disturbance, and voltage magnitude.
The report also must contain recommendations for statutory changes that would be necessary to enable the PSC properly to monitor and enforce standards to optimize power plant generating cost efficiency and minimize power quality disturbances, including recommendations to provide methods to ensure that Michigan can obtain optimal and cost-effective end-use customer power quality to attract economic development and investment into the State.
Review & Revision of PSC Rules. Under the bill, by December 31, 2009, based on its findings in the required report, the PSC must review its existing rules and amend them, if needed, to implement performance standards for generation facilities and for distribution facilities to protect end-use customers from power quality disturbances.
Any standards or rules developed under this provision must be designed to do the following, as applicable:
-- Establish different requirements for each customer class, whenever those different requirements are appropriate to carry out applicable provisions, and to reflect different load and service characteristics of each customer class.
-- Consider the availability and associated cost of necessary equipment and labor required to maintain or upgrade distribution and generating facilities.
-- 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.
-- 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.
-- Carefully consider the time frame for achieving a specified standard, taking into account the time required to implement needed investments or modify operating practices.
The PSC also must create benchmarks for individual jurisdictional entities within their rate-making process in order to accomplish the prescribed goals to alleviate end-use customer power quality disturbances and promote power plant generating cost efficiency.
The PSC must 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 that customer class.
Separation of Generation & Distribution Report. Within two years of the bill's effective date, the PSC must conduct a study and report to the Governor and the House and Senate standing committees with oversight of public utilities issues on the advisability of separating electric distribution and generation within electric utilities, taking into account the costs, benefits, efficiencies to be gained or lost, effects on customers, effects on the reliability or quality of service, and other factors that the Commission determines are important. The report must include the advisability of locating within separate departments of the utility the personnel responsible for the day-to-day management of electric distribution and generation and maintaining separate books and records for distribution and generation.
Purchasing Pool Report. Two years after the bill's effective date, the PSC must conduct a study and report to the Governor and the applicable House and Senate standing committees on whether the State would benefit from the creation of a purchasing pool in which electric generation in Michigan is purchased and then resold. The report must include whether the purchasing pool should be a separate entity from electric utilities, the impact of such a pool on utilities' management of their electrical generating assets, and whether ratepayers would benefit from spreading the cost of new electric generation across all or part of Michigan.
Distributed Generation. Within 270 days after the bill took effect, each regulated utility must file with the PSC a plan for using dispatchable customer-owned distributed generation within the context of its integrated resource planning process. The filing must include 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 customers to maintain these assets in dispatchable condition. If a utility already has programs addressing the subject of the required filing, it may refer to and take credit for those existing programs in its proposed plan.
Cooperative Suppliers. Under the Act, any retail customer of a cooperative with a peak load of at least one megawatt had to be given the opportunity to choose an AES by January 1, 2002. The bill deleted the reference to that date and instead requires that the customer be given this opportunity subject to provisions in the Act concerning PSC orders and the election to receive service from an AES.
Municipally Owned Utilities & AESs. Under the Act, the governing body of a municipally owned utility must determine whether it will permit its retail customers to choose an AES, subject to the implementation of rates, charges, terms, and conditions. Except with the written consent of the municipally owned utility, a person may not provide delivery service or customer account service to a retail customer that was receiving that service from a municipally owned utility as of June 5, 2000, or is receiving the service from a municipally owned utility. Previously, the Act referred to a retail customer who was receiving the service from a municipally owned utility and had the opportunity to choose the AES under terms consistent with the Act.
The Act had stated that these provisions did not apply after December 31, 2007, if the governing body of the municipally owned utility did not permit all of its retail customers receiving delivery service from that utility located outside the boundaries of the municipality that owned the utility the opportunity to choose an AES. The bill deleted this statement.
Municipally Owned Utilities & Electric Utilities. Previously, if a municipally owned utility elected to provide electric generation service to retail customers receiving delivery service from an electric utility, the municipally owned utility had to give all of its retail customers receiving delivery service from that utility located outside of the boundaries of the municipality the opportunity to choose an AES. The rates, charges, terms, and conditions of delivery service for customers choosing an AES had to be established by the governing body of the municipally owned utility. If a municipally owned utility and an electric utility both provided delivery service to retail customers in the same municipality located outside of the boundaries of the municipality that owned the municipal utility, the municipally owned utility had to make a filing or enter into a written agreement as provided in the Act.
Additionally, the municipally owned utility had to comply with certain orders issued pursuant to the Act with respect to customers located outside of the municipality that owned the utility. Upon a complaint or on the PSC's own motion, if the Commission found, after notice and hearing, that the municipally owned utility had not complied with a provision or order, the Commission had to order the remedies and penalties necessary to make whole a customer or other person who had suffered damages as a result of the violation, including one or more of the following:
-- Ordering the utility to pay a fine of not less than $1,000 or more than $20,000 for the first offense and not less than $40,000 for a second and any subsequent offense.
-- Ordering a refund to the customer of any excess charges.
-- Revoking the utility's license if the PSC found a pattern of violation.
-- Issuing cease and desist orders.
The municipally owned utility had to obtain a license as prescribed in the Act. The PSC had to issue a license unless it determined that the utility had adopted rates, charges, terms, and conditions for delivery service that were unduly discriminatory or reflected recovery of stranded costs in an amount considered unjust and unreasonable by the Commission. A municipally owned utility operating under a license had to notify the PSC before modifying rates, charges, terms, and conditions for delivery service. The PSC, after notice and opportunity for a hearing, could revoke a license if it determined that the utility was not in compliance with these provisions.
The bill deleted all of these provisions, as well as references to these provisions elsewhere in the Act.
PSC Jurisdiction: Municipally Owned Utility. The bill specifies that, as provided in Section 6 of the PSC law, the PSC does not have jurisdiction over a municipally owned utility. (Under that section, the Commission is vested with complete power and jurisdiction to regulate all public utilities in Michigan, subject to certain exceptions. The exceptions include a municipally owned utility.)
FTE Appropriation. For the fiscal year ending September 30, 2009, the bill appropriated to the PSC from the assessments imposed under Public Act 299 of 1979 the amount of $2.5 million to hire 25.0 full-time equated (FTE) positions to implement the provisions of the bill.
Senate Bill 1048
Qualified Home Improvement Credit
The bill allows a taxpayer with a maximum adjusted gross income of $37,500, or a husband and wife filing a joint return with a maximum adjusted gross income of $75,000, who purchases and installs a qualified home improvement for his or her principal residence during the tax year, to claim an income tax credit equal to 10% of the amount the taxpayer paid in the tax year for the purchase and installation of each qualified home improvement or $75, or for a husband and wife filing a joint return, $200, whichever is less. The credit applies to tax years beginning after December 31, 2008, and before January 1, 2012.
"Qualified home improvement" means the following items intended for residential or noncommercial use that meet or exceed the applicable Energy Star energy efficiency guidelines developed by the U.S. Environmental Protection Agency and the U.S. Department of Energy: insulation, furnaces, water heaters, windows, dishwashers, clothes washers, and refrigerators.
To claim the credit, the taxpayer must provide verification of the amount paid for the purchase and installation of the qualified home improvement along with documentation of its compliance with the Energy Star energy efficiency guidelines. The verification must be in a manner required by the Department of Treasury.
If the credit exceeds the taxpayer's tax liability for the tax year, the excess portion of the credit must be refunded.
Renewable Energy Standard Credit
For tax years beginning after December 31, 2008, and before December 31, 2012, a taxpayer with a maximum adjusted gross income of $65,000, or a husband and wife filing a joint return with a maximum adjusted gross income of $130,000, may claim a credit against the income tax equal to a percentage of the amount authorized for the customer's electric utility under Section 45(2)(a) of the Clean, Renewable, and Efficient Energy Act and paid during the tax year. If the credit exceeds the taxpayer's liability for the tax year, the excess portion of the credit may not be refunded. The percentage of the authorized amount is 25% for the 2009 tax year, and 20% for the 2010 and 2011 tax years.
(Under Section 45(2)(a) of the Clean, Renewable, and Efficient Energy Act, an electric provider must recover the incremental cost of compliance with the Act's renewable energy standard by an itemized charge on the customer's bill. A provider may not comply with the standard to the extent that recovery would have a retail rate impact that exceeds $3 per month per residential customer meter.)
"Electric utility" means that term as defined under Section 10g of the PSC law. (Under that section, the term means a person, partnership, corporation, association, or other legal entity whose transmission or distribution of electricity the Commission regulates under Public Act 106 of 1909, which governs the transmission of electricity, or the PSC law. The term does not include a municipal utility, affiliated transmission company, or independent transmission company.)
MCL 460.1001-460.1195 (S.B. 213)
460.4a et al. (H.B. 5524)
206.253 (S.B. 1048)
Legislative Analyst: Julie Cassidy
FISCAL IMPACT
Senate Bill 213
The bill increases the responsibilities of the Public Service Commission and the Energy Office, both located within the Department of Energy, Labor, and Economic Growth.
The increased costs for the PSC will result primarily from the need to hire additional staff at the Commission to implement the new programs that the bill establishes. These new responsibilities involve renewable energy plan approvals and biennial reviews, the renewable energy credit certification and tracking program, an annual renewable cost reconciliation, revenue recovery mechanisms, energy optimization plans and an energy optimization credit certification and trading program, approval of energy optimization service companies, designation of wind energy resource zones and staffing for the new Wind Energy Resource Zone Board, the establishment of a statewide program for net metering, increased public awareness of energy-saving activities, and goals for reduction of energy use in the State. The bill also requires the PSC to submit several reports, perform a study on the potential of wind as a source of commercial energy generation, and report on those findings to the Governor and the Legislature. The administrative costs of the PSC are appropriated in the budget for the Department of Energy, Labor, and Economic Growth and are funded by assessments paid by public utilities regulated by the Commission. Municipally owned utilities are not regulated by the PSC and are specifically excluded from paying these assessments; however, they are subject to some of the renewable portfolio standards outlined in the bill. The PSC estimated that the Commission needs substantial additional staff to implement the energy package. House Bill 5524 (Public Act 286 of 2008) provides the PSC with 25.0 full-time equated employees (FTEs) and $2.5 million of available public utility assessment revenue in FY 2008-09 to implement changes under the PSC law.
In addition, Senate Bill 213 increases the responsibilities of the Department of Management and Budget in consultation with the Energy Office. The additional responsibilities include the performance of an energy analysis of State-owned or -leased buildings, reviewing the cost of using LEED building code standards in new or remodeled State buildings, reviewing the cost of leasing buildings for State departments that meet the same standards, implementing a program to educate State employees on energy conservation, and assisting in meeting the goal of reducing State government's grid-based energy purchases by 25% by 2015 from the level of energy purchases made in FY 2001-02. The Energy Office is housed within the Public Service Commission and receives U.S. Department of Energy funding as well as public utility assessments. For FY 2008-09, the appropriation for the Office is $5.3 million and 9.0 FTEs. Funding for any additional costs associated with these new responsibilities will come from an increased allocation of public utility assessment revenue. It is estimated that the DMB will incur additional staffing costs, as well; however, the amount of additional costs is currently indeterminate and will not be known until further consultation with the Energy Office. It is likely that current appropriations to the DMB will be insufficient to cover the anticipated additional costs and thus an increase in appropriations will be required.
The bill also allows the imposition of civil fines for noncompliance with the proposed Act by alternative electric suppliers. The fines range from not less than $5,000 to not more than $50,000. Civil fines are deposited into the General Fund when no specific fund is identified for deposit.
Finally, to the extent that the cost recovery mechanism increases the costs of utility rates for consumers, governmental entities as consumers of energy will be subject to these increases.
House Bill 5524
The bill increases the responsibilities of the Public Service Commission. Additional staff will be required to implement the new programs that the bill establishes, including an optional program for certification of need for facilities changes, review of mergers, time lines for decisions, and changes to the electric choice program. The bill also requires the PSC to conduct several studies and report findings to the Governor and the Legislature, and requires the Commission to retain an independent consultant to monitor the rate phase-in process through 2015. As noted above, the administrative costs of the PSC are appropriated in the budget for the Department of Energy, Labor, and Economic Growth and are funded by assessments paid by public utilities regulated by the Commission. Municipally owned utilities are not regulated by the PSC and are specifically excluded from paying public utility assessments; however, under Senate Bill 213, these utilities are subject to PSC regulation for certain alternative energy programs. To meet the expanded responsibilities in the energy package, House Bill 5524 provides the PSC with an additional 25.0 full-time equivalent employees (FTEs) and a supplemental appropriation of $2.5 million in FY 2008-09 from public utility assessments.
Senate Bill 1048
The refundable energy efficiency home improvement credit will reduce income tax revenue an estimated $21.0 million annually beginning with the 2009 tax year. The nonrefundable utility renewable energy compliance cost credit would reduce income tax revenue an estimated $25.0 million if the new fee were in effect for all of the 2009 tax year; however, utilities are not expected to begin assessing this new fee until late in 2009. As a result, this credit will cost an estimated $9.0 million during the 2009 tax year and about $21.0 million during the 2010 and 2011 tax years. On a fiscal year basis, these credits will reduce General Fund/General Purpose revenue by an estimated $19.0 million in FY 2008-09 and $46.0 million in both FY 2009-2010 and FY 2010-2011. Local governments will not directly be affected by these tax credits.
Fiscal Analyst: Joe Carrasco
Elizabeth Pratt
Maria Tyszkiewicz
Jay WortleyAnalysis was prepared by nonpartisan Senate staff for use by the Senate in its deliberations and does not constitute an official statement of legislative intent. SB213/0910