*Percentage of the total number of kilowatt hours of electricity the provider sold to its Michigan retail customers for the calendar year
If a provider's portfolio in any of the specified periods exceeded the portfolio standard for that period, the excess could be carried forward and credited to a subsequent period.
Each provider would have to meet the renewable energy portfolio standard by one or more of the following means:
-- The generation of electricity from renewable energy systems for sale to retail customers in Michigan.
-- The purchase or other acquisition of unbundled renewable energy credits if, subject to certain conditions, the renewable energy system that generated the electricity for which the credit was issued were located within the geographic boundary of the applicable regional transmission organization (RTO).
-- Energy optimization under proposed Part 3, not exceeding 30% of the portfolio standard.
-- The acquisition of electricity generated by net metering customers subject to a proposed section of Public Act 3 of 1939, the PSC law.
-- Alternative compliance payments.
Additionally, a provider could purchase bundled renewable energy credits if one or both of the following requirements were met (subject to other requirements for an electric utility with 1.0 million or more retail customers):
-- The renewable energy system that generated the electricity for which each credit was issued was located in the United States and within the geographic boundary of the applicable RTO.
-- The electricity for which each credit was issued was delivered to the applicable RTO, to an electric utility's transmission system, or to another delivery point designated by a utility for the purpose of subsequent delivery to it.
A provider also could generate or acquire electricity from cleaner energy systems for sale to Michigan retail customers. A provider, however, could not use more than 20% of the electricity generated or acquired from clean energy systems for sale to Michigan retail customers to meet the portfolio standard.
("Bundled renewable energy credit" would mean a renewable energy credit that is acquired by an electric utility or AES in conjunction with a trade, purchase, or other transfer of renewable energy, or by an electric utility by the generation of renewable energy. "Unbundled renewable energy credit" would mean a renewable energy credit that is acquired by trade, purchase, or other transfer without acquisition of the renewable energy for the generation of which the credit was issued.
"Cleaner energy" would mean electricity generated using a "cleaner energy system, i.e., an IGCC facility, or other technologies for generating electricity as approved by the PSC by rule based on standards established by the Commission in consultation with the Departments of Natural Resources and Environmental Quality, to ensure that the technologies reduce or produce no carbon emissions; are reliable and cost-effective; comply with applicable Federal and State environmental and natural resources laws; do not harm the public health, safety, and welfare; and do not reduce property values.
"IGCC facility" would mean an integrated gasification combined cycle plant located in Michigan that produces synthetic or methanized synthetic gas from carbon-based feedstock, including coal, petroleum coke, wood, biomass, and other agricultural products, and uses that gas to generate electricity for commercial use. The term would include the transmission lines and facilities, gas transportation lines and facilities, and associated property and equipment employed specifically to serve that facility.)
A provider's integrated renewable energy portfolio would have to be calculated by the addition of all of the following:
-- The number of renewable energy credits used to comply with the proposed Act during the year.
-- The number of megawatt hours of electricity generated or acquired by the provider from cleaner energy systems during the year.
-- The number of megawatt hours of demand reduction through energy optimization under Part 3.
-- The number of megawatt hours of electricity acquired from net metering customers by the provider during the year.
-- The number of megawatt hours represented by alternative compliance payments.
The sum would have to be divided by one of the following at the option of the provider as specified in its renewable energy portfolio plan:
-- The number of weather-normalized megawatt hours of electricity the provider sold during the previous year to retail customers in Michigan.
-- The average number of megawatt hours the provider sold annually to retail customers in Michigan.
The quotient would have to be multiplied by 100.
Each provider would have to file an annual report with the PSC regarding its status in meeting the renewable portfolio standard.
Beginning in 2010, the PSC annually would have to evaluate the State renewable energy purchasing requirements under Section 257 of the Management and Budget Act, including the cost of purchasing renewable energy compared to energy from a new coal-fired power plant. In determining costs, the PSC would have to consider and quantify the transmission costs and capacity reliability of both renewable energy and electricity generated by a new coal-fired facility. (Senate Bill 1000 would add Section 257 to the Management and Budget Act to require that a certain percentage of the electrical energy purchased by the Department of Management and Budget be generated from a renewable energy source.)
A provider would have to recover the incremental cost of compliance with the renewable portfolio standard by an itemized charge on the customer's bill for billing periods beginning more than 90 days after PSC approval of the provider's plan. In its billing statement for a residential customer covering the end of a calendar year or as an insert to that statement, each provider would have to report the sum of the charges imposed on the customer during that year under Parts 2 and 3 of the proposed Act and advise that the sum paid by the customer was eligible for a State income tax credit. A provider could not comply with the renewable portfolio standard to the extent that, as determined by the PSC, recovery of the incremental cost of compliance and capacity reliability and quantified transmission costs pursuant to the plan, subject to annual revision, would have a retail rate impact that exceeded any of the following:
-- $2 per month per residential customer meter.
-- $11.05 per month per commercial secondary customer meter.
-- $125 per month per commercial primary or industrial customer meter.
("Customer meter" would mean an electric meter of a provider's retail customer. The term would 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 incremental cost of compliance would have to be calculated for a 20-year period beginning with approval of the plan and would have to be recovered on a levelized basis.
Upon petition by a provider, for good cause the PSC could grant two extensions of the renewable energy portfolio standard deadlines. Each extension could be for up to one year. Good cause would include 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 limited availability of renewable energy systems, if the provider exercised 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 limited 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 limited availability of renewable energy systems.
("Reasonable diligence" would include submitting timely applications for the necessary governmental approvals and making good faith efforts to ensure that the applications were administratively complete and technically sufficient.)
If two extensions of the 2015 standard deadline had been granted, upon a provider's subsequent petition at least three months before the second extended deadline expired, the provider would have to be considered to be in compliance with the proposed Act at an integrated renewable energy portfolio standard determined by the PSC to be attainable by that provider.
Any provider that made a good faith effort to spend the full amount of incremental costs of compliance as outlined in its approved plan, subject to any approved extensions or revisions, would have to be considered to be in compliance with the Act.
Renewable Energy Credits. Renewable energy credits could be traded, sold, or otherwise transferred. Credits that were not used by a provider to comply with an integrated renewable portfolio standard in a calendar year could be banked and carried forward indefinitely for the purpose of complying with a standard in a subsequent year. For the purpose of complying with a portfolio standard, in any calendar year, both of the following would apply:
-- Banked unbundled renewable energy credits would have to be used, up to the limit imposed by the proposed Act, before other credits were used.
-- Banked renewable energy credits with the oldest issuance date would have to be used to comply with the standard before banked credits with more recent issuance dates were used.
A provider would be responsible for demonstrating that a credit used to comply with a renewable energy portfolio standard was derived from a renewable energy source and that the provider had not used, traded, sold, or otherwise transferred the credit previously.
A provider could use the same renewable energy credit to comply with both a Federal renewable portfolio standard and an integrated renewable energy portfolio standard established under the proposed Act. A provider that used a credit to comply with a renewable portfolio standard imposed by any other state could not use the same credit to comply with a standard established under the Act.
Except as otherwise provided, unbundled renewable energy credits, including banked credits, could not be used to meet more than 20% of the requirements of the portfolio standard for any year. This limitation would not apply to credits issued for electricity generated in Michigan by a net metering facility, or another generating facility that was not connected directly to a distribution or transmission system. The limitation also would not apply to renewable energy credits issued for electricity generated in Michigan or issued by an AES.
A renewable energy credit would expire when a provider used it to comply with its renewable energy portfolio standard. A credit associated with the generation of electricity within 120 days after the start of a calendar year could be used to satisfy the prior year's standard and would expire when so used.
Utilities with at least 1.0 Million Customers. A provider that was an electric utility with at least 1.0 million retail customers in Michigan as of January 1, 2008, would have to obtain the renewable energy credits that were necessary to meet the renewable portfolio standard for the 2012 and 2014 calendar years as discussed below.
At the provider's option, a maximum of 50% of the credits could be from any of the following: renewable energy systems that were developed and owned by the provider, and renewable energy systems that were developed by one or more third parties pursuant to a contract with the provider under which the ownership of the system could be transferred to the provider, but not before the system began commercial operation. The provider would have to bid competitively any contract for engineering, procurement, or construction of any new systems. In the case of a transfer of ownership resulting from a contract, the transfer would not count toward the renewable energy system ownership limit. The contract would have to be executed after a competitive bidding process conducted pursuant to guidelines established by the PSC. An affiliate of the provider could 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.)
At least 50% of the credits would have to be from renewable energy contracts that did not require transfer of ownership of the applicable renewable energy system to the provider or from contracts for the purchase of renewable energy credits alone. A renewable energy contract or contract for the purchase of renewable energy credits also would have to be executed after a competitive bidding process conducted according to PSC guidelines. A provider's affiliate could submit a proposal in response to an RFP, subject to the code of conduct and the sanctions for a violation. Ownership of renewable energy systems by affiliates resulting from renewable energy contracts would not count toward the provider's new systems ownership limit. If a provider selected a bid other than the least price conforming bid from a qualified bidder, the provider promptly would have to notify the PSC. The Commission would have to determine whether the provider had good cause for selecting that bid. If the PSC determined that the provider did not have good cause, it would have to disapprove the contract.
These provisions would not apply to renewable energy credits that were transferred to the provider pursuant to the proposed Act. These provisions also would not apply to renewable energy credits that were 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, or use of industrial thermal energy in, electric generation facilities in existence when the Act took effect, except to the extent the number of megawatt hours generated annually by either of those methods exceeded the number of megawatt hours generated during the one-year period immediately before the Act's effective date.
For the purposes of obtaining credits to meet the standard, the method of procuring credits from a system that used water released from a pump storage facility would have to be considered to be the method of procuring the renewable energy used to pump water into the facility.
A provider could submit a contract for renewable energy credits to the PSC for review and approval. If the PSC approved the contract, it would have to be considered consistent with the provider's renewable energy portfolio plan.
Location or Source of System or Energy. The locational requirements for a provider to meet the integrated renewable energy portfolio standard would not apply if one or more of the following were met:
-- The renewable energy system was a wind turbine or wind farm that was under construction or operational and owned by a provider on January 1, 2008.
-- The renewable energy system was a wind farm, at least one of the wind turbines met these requirements, and the remaining turbines were within 15 miles of a wind turbine that was part of the wind farm and that met the requirements.
-- Before January 1, 2008, a provider that served 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 was served by that provider.
-- Electricity generated from the renewable energy system was 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 was not being used to meet another state's renewable portfolio standard.
-- Electricity generated from the renewable energy system was 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 was not being used to meet another state's renewable portfolio standard.
The locational requirements also would not apply if the renewable energy system were a wind turbine or wind farm and the electricity generated from the wind, or the renewable energy credits associated with that electricity, were being purchased under a contract in effect on January 1, 2008. If a provider used that electricity or those credits to meet portfolio requirements established after January 1, 2008, by the legislature of the state in which the wind turbine or wind farm was located, the provider, for the purpose of meeting the proposed Act's portfolio standard, could obtain, by any means authorized in the Act, up to the same number of replacement credits from any other wind farm or farms located in that state.
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 could 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.
Ownership of Credits. If a provider obtained renewable energy for resale to retail or wholesale customers under an agreement under the Public Utility Regulatory Policies Act (PURPA), ownership of the associated renewable energy credits would have to be as provided by the PURPA agreement. If the agreement did not provide for ownership of the credits, the following would apply:
-- Except to the extent that a separate agreement governed, for the duration of the PURPA agreement, for every five credits associated with renewable energy, ownership of four of the credits would have to be considered to be transferred to the provider with the renewable energy, and ownership of one credit would have to be considered to remain with the qualifying cogeneration facility or qualifying small power production facility.
-- If a separate agreement in effect on January 1, 2008, provided for the ownership of the renewable attributes of the generated electricity, the separate agreement would govern until January 1, 2013, or until the separate agreement expired, whichever occurred first.
("Qualifying cogeneration facility" would mean that term as defined in 16 USC 824a-3, i.e., a cogeneration facility (a facility that produces electric energy and steam or forms of useful energy, such as heat, that are used for industrial, commercial, heating, or cooling purposes) that the Federal Energy Regulatory Commission (FERC) determines meets requirements (including those related to minimum size, fuel use, and fuel efficiency) that FERC prescribes. "Qualifying small power production facility" would mean 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 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 obtained all or substantially all of its electricity for resale under a power purchase agreement or agreements in existence on the proposed Act's effective date, ownership of any associated renewable energy credits would have to be considered to be transferred to the provider purchasing the electricity. The number of credits associated with the purchased electricity would have to 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 was the amount of energy purchased under the agreement or agreements and the denominator of which was the total power supply of the seller during the term of the agreement. This provision would not apply unless one or both of the following occurred:
-- The seller and the provider purchasing the electricity agreed that it applied.
-- For a seller that was an independent investor-owned electric utility whose retail electric rates were regulated by the PSC, the Commission reduced the number of credits required under the renewable energy portfolio standard for the seller by the number of credits to be transferred to the provider purchasing the electricity.
Contract Terms. If, after the proposed Act took effect, a rate-regulated provider entered into a renewable energy contract or a contract to purchase unbundled renewable energy credits, the PSC would have to determine whether the contract provided reasonable terms and conditions that would ensure a favorable economic outcome for the provider and its customers and comply with the retail rate impact limits prescribed in the bill. In making this determination, the PSC would have to consider the contract price and term. If the contract were a renewable energy contract, the PSC also would have to 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.
-- 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 moved 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 would have to use standard rating agency, lender, and accounting practices for electric utilities in determining these costs, unless the impacts for the provider were known.
Credit Certification & Tracking. The PSC would have to establish a renewable energy credit certification and tracking program or rely upon the use of the existing GATS tracking certification systems of the RTOs whose boundaries included territory in Michigan. The program could be contracted to and performed by a third party through a system of competitive bidding. The program would have to include all of the following:
-- A process to certify renewable energy systems, including all existing systems operating on the proposed Act's effective date, as eligible to receive renewable energy credits.
-- Certification that the operator of a renewable energy system was in compliance with State and Federal law applicable to the operation of the system when certification was granted.
-- A method for the transferability of credits.
-- Determining the date that a credit was valid for transfer under the Act.
-- A method to ensure that each credit traded and sold was properly accounted for.
-- If the system were established by the PSC, allowance for issuance, transfer, and use of credits in electronic form.
If a renewable energy system became noncompliant with State or Federal law, credits could 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 would not have to be used in Michigan.
Granting of Credits; Incentive Credits. Except as otherwise provided, one credit would have to be granted to the owner of a renewable energy system for each megawatt hour of electricity generated from the system, subject to all of the following:
-- If a system used both a renewable energy resource and a nonrenewable energy resource to generate electricity, the number of renewable energy credits would have to be based on the percentage of the electricity generated from the renewable resource.
-- Credits could 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 its boilerplate capacity rating effective on January 1, 2008.
-- Credits could not be granted for renewable energy whose renewable attributes were used by a provider in a PSC-approved voluntary renewable energy program.
Credits also could not be granted for the generation of renewable energy, such as wind energy, used to pump water into a pumped storage facility or to fill other energy storage facilities, but would have to be granted for renewable energy generated upon release from a pumped storage or other energy storage facility. The number of credits, however, would have to be calculated based on the number of megawatt hours of renewable energy used to fill the storage facility, not the number of megawatt hours actually generated by discharge from it.
Subject to those conditions, the following additional renewable energy credits, to be known as Michigan incentive renewable energy credits, would have to 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, 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.
The credits for Michigan-made equipment and a Michigan workforce would be available for the first three years after the renewable energy system first produced electricity on a commercial basis.
Alternative Compliance Rate. The PSC would have to establish an alternative compliance rate for each compliance year for each provider that was subject to an integrated renewable portfolio standard. The rate would have to be expressed in dollars per megawatt hour.
The PSC would have to establish an alternative compliance rate based on the cost of qualifying electricity, contracts that the provider had acquired for future delivery of qualifying electricity, and the number of unbundled renewable energy credits that the provider anticipated using in the compliance year to meet the applicable portfolio standard.
A provider could make voluntary alternative compliance payments to comply with the applicable standard. Payments would have to be recovered in the provider's rates, subject to the retail rate impact limits prescribed in the bill.
Each provider would have to deposit any amounts recovered in its rates for alternative compliance payments in a holding account. Amounts in the holding account would have to accrue interest at the rate of return authorized by the PSC for the provider. These provisions would not apply to an AES.
A provider could spend amounts in holding accounts only for costs of acquiring new generating capacity from renewable energy sources, investments in efficiency upgrades to electricity generating facilities owned by the provider, and energy optimization programs within the provider's service area. The PSC would have to approve expenditures by a provider from a holding account. These provisions would not apply to an AES.
The PSC would have to require AESs to establish holding accounts and make payments to those accounts on a substantially similar basis as provided for electric utilities. The PSC would have to approve expenditures by an AES from a holding account. The PSC could approve expenditures only for energy conservation programs for customers of the AES.
The PSC would have to establish initial alternative compliance rates by July 1, 2009.
Failure to Meet Act's Requirements. If a rate-regulated provider failed to meet the renewable energy portfolio standard by the applicable deadline, subject to the provisions regarding extensions, the provider would have to purchase sufficient renewable energy credits necessary to meet the standard or make mandatory alternative compliance payments at the established rate to meet the standard. The provider could not recover from its ratepayers the cost of purchasing renewable energy credits or making alternative compliance payments if the PSC found that the provider did not make a good faith effort to meet the goals of the renewable energy portfolio standard by the applicable deadline, subject to the extension provisions.
The Attorney General or any customer of a municipally owned or cooperative electric utility that had elected to become member-regulated under the Electric Cooperative Member-Regulation Act could bring a civil action for injunctive relief against the utility if it failed to meet the applicable requirements of the proposed Act.
An action would have to be brought in the circuit court for the circuit in which the provider's principal office was located. An action could not be filed unless the prospective plaintiff had given the prospective defendant 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 prospective defendant received notice of the intent to sue, the parties would have to meet and make a good faith attempt to determine if there was a credible basis for the action. If both parties agreed that there was, the prospective defendant would have to take all reasonable steps necessary to comply with the applicable requirements of the proposed Act within 90 days of the meeting.
In issuing a final order in an action brought against a utility, the court could award costs of litigation, including reasonable attorney and expert witness fees, to the prevailing or substantially prevailing party.
Upon a complaint of an AES's customer or on the PSC's own motion, the PSC could conduct a contested case to review allegations that the AES had violated the proposed Act, including an order issued or rule promulgated under it. If the PSC found, after notice and hearing, that an AES had violated the Act, the Commission would have to 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.
Regulated Provider Tariffs. For a provider whose rates were regulated by the PSC, the Commission would have to determine the appropriate charges for the provider's tariffs that permitted recovery of the incremental cost of compliance subject to the retail rate impact limits prescribed in the bill.
Implementation & Compliance Costs. Notwithstanding any other provision of law, the PSC would have to consider all actual costs reasonably and prudently incurred in good faith by a rate-regulated provider to implement a Commission-approved integrated renewable energy portfolio plan, to be a cost of service to be recovered by the provider, whether or not those costs were incremental costs of compliance. Notwithstanding any other provision of law, a rate-regulated provider would have to recover through its retail electric rates all of the provider's incremental costs of compliance and all reasonable and prudent ongoing costs of compliance, subject to the retail rate impact limits. The recovery would have to include the provider's authorized rate of return on equity, which would have to 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 portfolio plan was approved. The costs of purchasing renewable energy credits or alternative compliance payments could not be recovered under these provisions if recovery were not allowed due to failure to meet the renewable energy portfolio standard by the applicable deadline.
Incremental costs of compliance would have to be calculated by determining the sum of the following costs to the extent that they were reasonable and prudent and not already approved for recovery in electric rates as of the proposed Act's effective date:
-- Capital, operating, and maintenance costs of renewable energy systems, cleaner energy systems, and energy optimization, including property taxes, insurance, and return on equity associated with a provider's renewable energy and cleaner energy systems and energy optimization, including the provider's integrated renewable energy portfolio established initially to achieve compliance with the portfolio standard and any additional renewable energy systems, cleaner energy systems, and energy optimization that the provider built, acquired, or implemented to maintain compliance with the standard, beginning when the provider's plan was approved by the PSC.
-- Financing costs attributable to capital, operating, and maintenance costs of capital facilities associated with renewable energy systems, cleaner energy systems, and energy optimization.
-- Transmission, interconnection, and substation costs associated with renewable energy systems, cleaner energy systems, and energy optimization.
-- Except to the extent that the costs were allocated under a different provision, the costs of renewable energy credits purchased or alternative compliance payments under the proposed Act other than those for which a provider was denied recovery due to failure to meet the renewable energy portfolio standard deadline, and the costs of renewable energy credit contracts.
-- Expenses incurred as a result of State or Federal governmental actions related to renewable energy systems, cleaner energy systems, or energy optimization, including changes in tax or other law.
-- Any additional provider costs the PSC considered relevant.
The sum of the following revenue would have to 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 cleaner energy.
-- Interest on regulatory liabilities.
-- Tax credits specifically designed to promote renewable energy systems, cleaner energy systems, or energy optimization.
-- Revenue derived from the provision of renewable energy or 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 energy or cleaner energy sales.
-- Any additional provider revenue the PSC considered relevant.
(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, could 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, beginning in 2008, after providing an opportunity for a contested case hearing for a rate-regulated provider, the PSC annually would have to establish a price per megawatt hour. In addition, a rate-regulated provider could petition the PSC to revise the price at any time. In setting the price per megawatt hour, the PSC would have to 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 would have to be multiplied by the number of megawatt hours of renewable energy. The resulting value would have to be considered a booked cost of purchased and net interchanged power transactions under Section 6j of the PSC law. For energy purchased by such a provider under a renewable energy agreement, the price would have to be the lower of the amount established by the PSC or the actual price paid, and would have to be multiplied by the number of megawatt hours of renewable energy purchased. The resulting value would have to be considered a booked cost of purchased and net interchanged power under Section 6j.
The PSC would have to authorize a rate-regulated provider to spend in any given month more to comply with the proposed Act and implement an approved integrated renewable energy portfolio plan than the revenue actually generated by the revenue recovery mechanism. A rate-regulated provider would have to recover its Commission-approved pretax rate of return on regulatory assets during the appropriate period, and would have to 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 of renewable energy or cleaner energy costs through the PSCR clause under Section 6j of the PSC law would have to continue to be reconciled under that section.
If a provider's incremental costs of compliance in any given month were in excess of the adjusted revenue recovery mechanism and in excess of the balance of any accumulated reserve funds, subject to the minimum balance established by the PSC, the provider immediately would have to notify the PSC. The Commission promptly would have to commence a contested case hearing and modify the revenue recovery mechanism so that the minimum balance was restored.
If a rate-regulated provider had a regulatory liability, the refund to customer classes would have to be proportional to the amounts they paid under the revenue recovery mechanism.
Renewable Cost Reconciliation for Regulated Providers. These provisions would apply only to a provider whose rates were 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 would have to commence an annual proceeding, to be known as a renewable cost reconciliation, for each rate-regulated provider. The reconciliation proceeding would have to be conducted as a contested case hearing under the APA. Reasonable discovery would have to 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 could propose any necessary modifications of the revenue recovery mechanism to ensure the provider's recovery of its incremental cost of compliance with the integrated renewable energy portfolio standard.
The PSC would have to 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 would have to 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 would have to do all of the following:
-- Determine the provider's compliance with the renewable energy portfolio 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 cleaner energy capacity and for renewable energy and cleaner energy to be recovered through the PSCR clause, as outlined above.
-- Adjust the minimum balanced of accumulated reserve funds established by the PSC, if necessary.
With regard to the adjustment of the revenue recovery mechanism, the PSC would have to ensure that the retail rate impacts under the renewable cost reconciliation revenue recovery mechanism did not exceed the maximum retail rate impacts specified in the bill. The PSC would have to ensure that the recovery mechanism was projected to maintain a minimum balance of accumulated reserve so that a regulatory asset did not accrue.
If a provider had recorded a regulatory liability in any given month, interest on the regulatory liability balance would have to be accrued at the average short-term borrowing rate available to the provider during the appropriate period, and would have to be used to fund incremental costs of compliance incurred in subsequent periods.
Provider & PSC Reports. By a time the PSC determined, each provider would have to submit to the Commission an annual report that provided information relating to the provider's actions to comply with the integrated renewable energy portfolio standard. By the same time, a municipally owned electric utility would have to submit a copy of the report to its governing body, and a cooperative electric utility would have to submit a copy of the report to its board of directors.
Each annual report would have to 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, or traded during the reporting period.
-- The amount of electricity that the provider generated or acquired from cleaner energy systems during the reporting period.
-- The capacity of each renewable energy system and cleaner energy system owned, operated, or controlled by the provider, the total amount of electricity generated by each renewable energy system or 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 cleaner energy system during the reporting period.
-- Expenditures made in the past year and anticipated future expenditures to comply with Parts 2 and 3.
-- Any other information that the PSC determined necessary.
Concurrently with the submission of each report, a municipally owned electric utility would have to submit a summary of the report to its customers with a bill insert and to its governing body, and a cooperative electric utility would have to submit a summary to its members in a periodical issued by an association of rural electric cooperatives and to its board of directors. A municipally owned utility or cooperative electric provider would have to make a copy of the report available at its office and post a copy on its website. A summary would have to indicate that a copy of the report was available at the office or website.
The PSC would have to monitor the reports and ensure that actions taken under the proposed Act by providers serving customers in the same distribution territory did not create an unfair competitive advantage for any of those providers.
Biennially, the PSC would have to submit a report to the Legislature. The report would have to do all of the following:
-- Summarize data collected under these provisions.
-- Discuss the status of renewable and cleaner energy in Michigan and the effect of Parts 2 and 3 on electricity prices.
-- Specify the difference between the cost of the renewable energy and the cost of electricity generated from conventional sources, for each of the different types of renewable energy sold at retail in Michigan.
-- 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 bill.
-- Discuss how the PSC was fulfilling the requirements of monitoring the reports and ensuring that actions taken under the proposed Act by providers serving customers in the same distribution territory did not create an unfair competitive advantage for any of those providers.
Within one year after the bill took effect, the PSC would have to report to the Legislature on the potential rate impacts on all customer classes if rate-regulated providers decoupled rates. The PSC's report would have to review whether decoupling would be cost effective and would reduce the overall consumption of fossil fuels in Michigan.
Confidential Information. A person confidentially could file commercially or financially sensitive information or trade secrets with the PSC or a third party contractor under the proposed Act. The information would have to be accompanied by an affidavit that set forth both the reasons for the confidentiality and a public synopsis of the information.
The information would be exempt from the Freedom of Information Act and would have to remain confidential, except under the terms of a mandatory protective order. If information were disclosed under such an order, the PSC could use it for the purpose for which it was required, but the information would have to remain confidential.
The bill would establish a rebuttable presumption that any information filed confidentially was commercially or financially sensitive information or trade secrets entitled to protection.
Temporary Order & Implementation Rules. Within 60 days after the effective date of the proposed Act, the PSC would have to issue a temporary order implementing it, including formats of integrated renewable energy portfolio plans for various categories of providers and guidelines for RFPs under the Act.
Within one year after the Act took effect, the PSC would have to promulgate rules to implement it.
Merchant Plant Recovery. If, on or before January 1, 2008, a merchant plant entered into a contract with an initial term of at least 20 years to sell electricity to a rate-regulated provider with at least 1.0 million retail customers in Michigan, and if the merchant plant generated electricity under the contract, in whole or in part, from a renewable energy resource, wood, wood waste, or landfill gas, the merchant plant would have to recover the amount, if any, by which the plant's actual and reasonably incurred fuel and variable operation and maintenance costs exceeded the amount that the AES was paid under the contract for those costs.
The PSC would have to issue orders to permit the authorized recovery through the PSCR process of the provider upon petition of the merchant plant. The plant could not be required to alter or amend the existing contract with the electric utility in order to obtain the recovery. The PSC would have to permit or require the provider to recover from its ratepayers fuel and variable operation and maintenance costs under the contract as reasonably and prudently incurred costs.
Other Provisions. The proposed Act would not give the PSC new authority with respect to municipally owned electric utilities except to the extent explicitly provided in the Act.
Notwithstanding any other provisions of Part 2, electricity or natural gas used in the operation or testing of any environmental control equipment authorized, permitted, or required by the State, any Federal agency, or any court order would be exempt from the requirements of, and calculations of compliance required under, Part 2.
Part 3: Energy Optimization
Energy Optimization Plan; Goal. Within 90 days after the PSC entered a temporary order implementing the proposed Act, each provider would have to file a proposed energy optimization plan with the Commission. (As used in proposed Part 3, "provider" would mean an electric provider or a natural gas provider. "Natural gas provider" would mean an investor-owned business engaged in the sale and distribution of natural gas within Michigan whose rates are regulated by the PSC.)
For an electric provider, the proposed plan would have to be prepared and subject to approval as a subpart of the integrated renewable energy portfolio plan. For a natural gas provider, the proposed energy optimization plan would be subject to approval in the same manner as an electric provider's integrated renewable energy portfolio plan under Part 2.
An energy optimization plan could use energy efficiency, load management, and conservation programs. An optimization plan also could use educational programs designed to alter consumer behavior or any other measures that could be used reasonably to meet the goals set forth in the bill (as described below).
The overall goal of an energy optimization plan would be to reduce the future costs of provider service to customers. In particular, the plans would have to be designed to protect consumers from the higher costs that would follow the construction of new electric generating plants by delaying the need for their construction.
As part of an optimization plan filing, a provider could propose to the Commission measures designed to meet the prescribed goal, which would provide additional customer benefits.
An optimization plan would have to provide for the practical and effective administration of the proposed energy optimization programs. The PSC would have to allow providers flexibility in designing their programs and administrative approach. At the option of a provider, its programs could be administered 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.
("Energy optimization" would mean energy efficiency, load management, and conservation. "Load management" would mean measures or programs that target equipment or devices to result in decreased peak electricity demand or shift demand from peak to off-peak periods.)
PSC Review of Plans. A provider's energy optimization plan would have to be filed, reviewed, and approved or rejected by the PSC as part of the same procedures that would apply to the integrated renewable energy portfolio plan.
The PSC could not approve an integrated renewable energy portfolio plan unless it determined that the energy optimization plan was reasonable. In making this determination, the PSC would have to review each element and consider whether it would reduce the future cost of service for the provider's customers. In addition, the PSC would have to consider at least all of the following:
-- The specific changes in customers' consumption patterns that the proposed optimization plan was attempting to influence.
-- The cost and benefit analysis and other justification for specific programs and measures included in a public utility's proposed energy optimization plan.
-- Whether the proposed optimization plan was consistent with any long-range integrated resource plan filed by the public utility with the PSC.
-- Whether the proposed optimization plan would result in any unreasonable prejudice or disadvantage to any customer class.
-- The extent to which the plan provided programs that were available, affordable, and useful to all customers.
Financial Incentives. A provider could request and the PSC could approve, as part of an energy optimization plan, the payment of a financial incentive to the provider designed to reward commensurately the provider for positive performance. The total amount of the incentive, however, could not exceed 50% of the net cost reductions enjoyed by the provider's customers as a result of implementation of the plan.
Incremental Costs. The incremental costs of a provider's optimization programs would have to include the full costs incurred pursuant to its optimization plan and revenue that represented contributions to the provider's fixed costs that were lost because of the plan's implementation.
The incremental costs of a provider's optimization programs, including costs paid to an energy efficiency program administrator, would have to be quantified on a per-meter basis and included in the incremental costs of compliance subject to the retail rate impact limits prescribed in the bill.
The PSC could assign and charge for the costs of various energy optimization educational programs only to the class or classes of customers that benefited from those programs.
Energy Efficiency Program Administrator. The bill's provisions regarding energy optimization plans, plan goals, PSC review, and financial incentives would not apply to a provider that paid the following minimum percentage of total utility sales revenue, including electricity or natural gas commodity costs, each year to an independent energy efficiency program administrator selected by the PSC:
-- In 2009, 0.75% of total utility sales revenue for 2007.
-- In 2010, 1.0% of total utility sales revenue for 2008.
-- In 2011, 1.5% of total utility sales revenue for 2009.
-- In 2012 and each subsequent year, 2.0% of total utility sales revenue for the preceding year.
Money the program administrator received from a provider would have to be used to administer energy efficiency programs for the provider. Money unspent in a given year would be carried forward to be spent the subsequent year.
The PSC would have to allow a provider that paid the program administrator to recover the amount of money transferred. This cost would have to 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.
Money a provider paid to the program administrator could be used only to fund energy efficiency programs in that provider's service territory. To the extent feasible, charges collected from a particular customer rate class and paid to the administrator would have to be devoted to energy efficiency programs for that rate class. The administrator would have to report to the PSC the demand reduction achieved for the provider through energy optimization for the purpose of calculating the integrated renewable energy portfolio under the proposed Act.
Money paid to the administrator that it did not spend that year would have to remain available for expenditure the following year, subject to the requirements regarding the allocation of money between different service territories and customer classes.
The PSC would have to select a qualified nonprofit organization to serve as the administrator through a competitive bid process. The Commission also would have to arrange for a biennial audit of the administrator.
Natural Gas Rate Decoupling. A natural gas utility regulated by the PSC would have to be allowed to decouple rates for residential and small commercial customers by implementing, at the utility's election, one of the following decoupling options:
-- A single per customer class fixed monthly service charge to recover the revenue requirement authorized in its most recent base rate case in place of the customer charges and volumetric distribution charges for those classes.
-- A symmetrical volumetric decoupling mechanism to recover from or return to customers the difference between the monthly revenue requirements authorized in its most recent base rate case to the actual revenue recovered from each customer class.
With regard to the second option, the overrecovery or underrecovery would have to be collected from or returned to customers in the second month following the overcollection or undercollection.
On an annual basis, a natural gas utility using either decoupling mechanism would have to implement a true-up mechanism in a manner determined by PSC order to adjust for variable costs incurred by the utility that were above or below the costs used to determine the revenue requirement authorized in its most recent base rate case; and the PSC would have to authorize the natural gas provider to decouple rates, regardless of whether, under Section 43, the provider's energy optimization programs were administered by the provider, a State agency, or a nonprofit organization.
(Section 43 provides that the overall goal of an energy optimization plan would be to reduce the future costs of service to customers, particularly by delaying the need for the construction of new generating plants.)
Part 4: State Government Energy Efficiency & Conservation
Energy Office. The Energy Office in the Department of Labor and Economic Growth would have to assist the Department of Management and Budget (DMB) in conducting energy audits to improve energy performance of facilities owned or leased by the State and implementing the recommendations of the audits if they would save money. If building or facility modifications were allowed under the terms of a lease, the State would have to undertake any recommendations resulting from an energy audit to those facilities if they would save money. The audits would have to be conducted by December 31, 2009, and every five years after that. Any money saved by the audits would have to be deposited into the proposed Energy Conservation Fund.
Additionally, the Energy Office would have to do all of the following:
-- Assist the DMB in examining the cost and benefit of using LEED (Leadership in Energy and Environmental Design) building code standards when constructing or remodeling a State building.
-- Assist the DMB, before the State leased a building, in examining the cost and benefit of leasing a building that met LEED building codes standards (unless there were no such buildings available that met the State's functional or physical needs, or the State already were leasing a building that had historical, architectural, or cultural significance that could be harmed by a lease not being renewed solely based on the building's failure to meet LEED criteria).
-- Assist each State department in appointing an energy manager to work with the Energy Office and that department to reduce State energy use.
-- Assist the DMB in ensuring that, during any renovation or construction of a State building, energy efficient products were used whenever possible and that the State purchased those products whenever possible.
-- Assist the DMB in implementing a program to educate State employees on how to conserve energy, which would have to be updated every three years.
-- Assist the PSC and the DMB in using more cost-effective lighting technologies, geothermal heat pumps, and other cost-effective technologies to conserve energy.
-- Assist the DMB, by March 31, 2010, in reducing the State's energy use during peak summer energy use seasons with the goal of achieving reductions beginning in 2010.
-- Assist the DMB in creating a web-based system for tracking energy efficiency and energy conservation projects occurring within State government.
-- With the PSC, review and increase efforts to give customers, particularly residential customers, information on energy efficiency and conservation.
By December 31, 2009, the Energy Office would have to prepare a report to the Legislature on what steps had been taken to increase awareness of energy efficiency and energy conservation methods.
PSC Duties. The PSC would have to do all of the following:
-- Undertake activities to increase public awareness of load management techniques (i.e., measures or programs that target equipment or devices to result in decreased peak electricity demand or shift demand from peak to off-peak periods).
-- Engage in regional efforts to reduce the demand for energy whenever possible.
-- Work with large commercial and industrial customers to reduce demand and conserve energy through load management techniques and other activities it considered appropriate.
By December 31, 2010, the PSC would have to file with the Legislature a report on the effort to reduce demand. The report also would have to include any recommendations for legislative action that the PSC considered necessary.
Energy Use Reduction Goals. The bill states, "It is the goal of this state to reduce energy use in this state by 5% by 2015. It shall be the goal of state government to reduce energy use by state government by 20% by 2015."
By April 1, 2010, and ever two years after that, the PSC would have to report to the Legislature on the progress being made toward those goals. By October 1, 2010, the PSC would have to report to the Legislature on how electric suppliers had progressed with implementing the energy use reductions. The PSC could use an independent evaluator to review the submissions by electric suppliers.
Energy Conservation Fund. The bill would create the Energy Conservation Fund within the State Treasury. The State Treasurer could receive money or other assets from any source for deposit into the Fund. The State Treasurer would have to direct investment of the Fund, and credit to it any earnings from the investments. Money in the Fund at the close of the fiscal year would remain in the Fund and would not lapse to the General Fund. The Department of Labor and Economic Growth would have to be the administrator of the Fund for auditing purposes. The PSC would have to spend Fund money, upon appropriation, to fund energy efficiency and conservation efforts. The Auditor General would have to audit the Fund by December 31, 2013.
Part 5: Wind Energy Resource Zones
Wind Energy Resource Zone Board. Within 60 days after the proposed Act took effect, the PSC would have to create the Wind Energy Resource Zone Board. The nine-member Board would have to 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.
-- Municipalities (i.e., cities, townships, and villages).
-- The electric transmission industry.
-- The public at large.
("Electric utility" would mean a person, partnership, corporation, association, or other legal entity whose transmission or distribution of electricity the PSC regulates under Public Act 106 of 1909. The term would not include a municipal utility, affiliated transmission company, or independent transmission company. "Independent transmission company" would mean a legal entity, or its successors or assigns, engaged in Michigan in the transmission of electricity using facilities it owns that have been divested to it by an electric utility that was engaged in the generation, transmission, and distribution of electricity in Michigan on December 31, 2000, and is independent of an electric utility or an affiliate of the utility, generating or distributing electricity to Michigan retail customers.
"Affiliated transmission company" would mean a legal entity, or its successors or assigns, that has satisfied fully the requirements to join an RTO as determined by FERC, is engaged in Michigan in the transmission of electricity using facilities it owns that were transferred to it by an electric utility that was engaged in the generation, transmission, and distribution of electricity in Michigan on December 31, 2000, and is not independent of an electric utility or an affiliate of the utility, generating or distributing electricity to Michigan retail customers.)
The Board would have to exercise its powers, duties, and decision-making authority under Part 5 independently of the PSC. The Board would have to do all of the following:
-- Study wind energy production potential and the viability of wind as a source of commercial energy generation in Michigan.
-- Study availability of land in Michigan for potential use by wind energy conversion facilities.
-- Conduct modeling and other studies related to wind energy, including studying existing wind energy conversion facilities, estimates for additional wind energy conversion facility development, and average annual recorded wind velocity levels.
The Board's studies would have to include examination of wind energy conversion facility requests currently in the applicable RTO's generator interconnection queue.
("Wind energy conversion facility" would mean a wind energy conversion system in Michigan that collects and converts wind into energy to generate electricity.)
Within 240 days after the proposed Act took effect, the Board would have to provide 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 cost-effective generating capacity in megawatts that could be installed in each identified region of the State.
-- An estimate of the annual maximum and minimum cost-effective energy production potential for each identified region.
-- An estimate of the maximum wind generation capacity already in service in each identified region.
After the Board issued 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 would have to identify existing or new transmission infrastructure necessary to deliver maximum and minimum wind energy production potential for each of those regions, and would have to 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, would have to designate an area of the State likely to be most productive of wind energy as the primary wind energy resource zone, and could designate additional zones. A wind energy resource zone would have to be created on land that was entirely within the State's boundaries. A zone would have to encompass a natural geographical area or region of the State as identified by the Board in its report. In determining the location of a zone, the PSC would have to ensure that there were not adverse impacts on the public health, safety, or welfare and that any adverse impacts on private property values were minimal. Additionally, the PSC would have to 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 could be used by wind energy conversion facilities.
-- Existing wind energy conversion facilities in the region.
-- Potential for megawatt output of combined wind energy conversion facilities in the region.
-- Received transmission request forms.
In conjunction with the issuance of its order, the PSC would have to submit to the Legislature a report on the effect that setback requirements and noise limitations under local zoning or other ordinances could have on wind energy development in wind resource zones. The report would have to include any recommendations the PSC had for legislation addressing those issues. Before preparing the report, the PSC would have to conduct hearings in various areas of the State to receive public comment on the subject of the report.
Expedited Siting Certificates. To facilitate transmission of electricity generated by wind energy conversion facilities located in wind resource zones, the PSC would have to issue expedited siting certificates to an electric utility, affiliated transmission company, or independent transmission company as provided in Part 5. A wind energy conversion facility that was issued an expedited certificate would be exempt from any local zoning ordinance except for provisions regulating setbacks and noise.
An electric utility, affiliated transmission company, or independent transmission company would have to apply to the PSC for an expedited siting certificate. An applicant could withdraw an application at any time.
Before applying for expedited siting of a proposed transmission line, an electric utility, affiliated transmission company, or independent transmission company would have to receive any required approvals from the applicable RTO for the proposed line. ("Transmission line" would mean 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 would have to give the PSC written notice that it would seek such approval. The PSC would have to represent the State's interests in all proceedings before the applicable RTO for which the PSC received notice.
An application for an expedited siting certificate would have to 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 would comply with all applicable State and Federal environmental standards, laws, and rules.
-- A copy of the Board's report evidencing cost-effective wind potential in the zone, and an explanation of how the proposed line would enable that potential.
-- Other information the PSC reasonably required by rule.
Upon applying for a certificate, an electric utility or transmission company would have to give public notice in the manner and form the PSC prescribed of an opportunity to comment on the application. Notice would have to be published in a newspaper of general circulation in the relevant zone within a reasonable time period after an application was given to the PSC, and would have to be sent to each affected municipality (i.e., a city, township, or village) and each affected landowner on whose property a portion of the proposed line would be constructed. The notice would have to be written in plain, nontechnical, and easily understood terms, and would have to contain a title that included 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 would have to conduct a proceeding on the application as a contested case under the APA.
The Commission would have to grant an expedited siting certificate if it determined all of the following:
-- The proposed line received all required approvals from the applicable RTO.
-- The proposed line would not result in an adverse impact on the public health, safety, or welfare and that any adverse impacts on private property values would be minimal.
-- The proposed line would comply with all applicable State and Federal environmental laws.
If the PSC granted a certificate, it would take precedence over a conflicting local ordinance, law, rule, regulation, policy, or practice that prohibited or regulated the location or construction of a transmission line for which the PSC had issued a certificate.
In an eminent domain or other related proceeding arising out of or related to a transmission line for which expedited siting authority was issued, a certificate approved under Part 5 would be conclusive and binding as to the necessity for that transmission line and its compatibility with the public health and safety.
The PSC would have up to 180 days to grant or deny an expedited siting certificate.
Wind Energy Conversion Facility Certification. A person who planned to construct a wind energy conversion facility within a wind energy resource zone could apply to the PSC for certification of the facility. An application would have to contain the following:
-- The location of the facility, including a detailed description of the land.
-- A certification that the applicant would own the facility.
-- The planned date for beginning construction of the facility.
-- If a zoning ordinance prohibited or regulated the location, development, or construction of the facility, a description of the manner in which the ordinance did so.
-- The estimated amount of the facility's annual energy production potential.
-- Any other information the PSC reasonably required by rule.
Within 30 days after receiving an application, the PSC would have to approve it and certify the facility if it determined all of the following:
-- Construction had not begun on the facility.
-- The facility would be located within a wind energy resource zone.
-- The facility would optimize benefits from wind energy cost effectively by meeting a minimal capacity factor.
The PSC could revoke a facility's certification if it were no longer in operation, or did not begin construction or become operational within 36 months from the date the certificate was granted and became final, and the PSC determined that an extension of time was unreasonable.
PSC Wind Energy Report. By the first Monday of March each year, the PSC would have to make to the Governor and the Legislature a report summarizing the impact of establishing wind energy resource zones, wind energy generation, expedited transmission line siting applications, estimates for future wind generation within the zones, and recommendations for program enhancements or expansion.
Transmission Line Construction. The bill specifies that Part 5 would 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 5. The PSC could promulgate rules to implement Part 5 pursuant to the APA. A PSC order relating to any matter provided for under Part 5 would be subject to review as provided in Section 26 of Public Act 300 of 1909 (which governs railroads). In administering Part 5, the PSC would have only those powers and duties granted to it under that part. Part 5 would control in any conflict between it and any other law of the State. Part 5 would not confer the power of eminent domain.
(Section 26 of Public Act 300 pertains to judicial appeals of Commission orders fixing rates, fares, charges, classifications, joint rates, regulations, practices, and services.)
Severability
As provided in Section 5 of 1846 RS 1, the proposed Act would be 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, and to this end, acts are declared to be severable.)
Legislative Analyst: Julie Cassidy
FISCAL IMPACT
The bill would increase the responsibilities of the Public Service Commission and the Energy Office, both located within the Department of Labor and Economic Growth.
The increased costs for the PSC would result primarily from the need to hire additional staff at the PSC to implement the new programs that the bill would establish. These new responsibilities would involve renewable energy portfolio plan approvals and biennial reviews, the renewable energy credit certification and tracking program, an annual renewable cost reconciliation, revenue recovery mechanisms, energy optimization plans, alternative compliance rates, wind energy resource zones, increased public awareness of energy-saving activities, and goals for reduction of energy use in the State. The bill also would require 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 Labor and Economic Growth and are funded by assessments paid by public utilities regulated by the Commission. Municipally owned utilities under current law are not regulated by the PSC and are specifically excluded from paying these assessments; however, they would be subject to some of the renewable portfolio standards outlined in the bill. According to the PSC, it is estimated the Commission would need to hire between 25 and 30 additional staff to meet these new responsibilities. It is estimated the cost of these FTEs would be from $2.4 million to $2.9 million.
The increased responsibilities in the Energy Office would include the performance of energy audits of State-owned or -leased buildings, working with the DMB on 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 working to assist in meeting the goal of reducing energy use in State government by 20% by 2015. The bill also would create the Energy Conservation Fund. Revenue to this Fund would include those savings realized through the energy audits. These funds would be available upon appropriation to the PSC for energy efficiency and conservation efforts. The Energy Office is housed within the Public Service Commission and is funded with U.S. Department of Energy funding as well as public utility assessments. For FY 2007-08, the appropriation for the Office is $5.3 million and 9.0 FTEs. Any additional costs associated with these new responsibilities would come from an increased allocation of public utility assessment revenue.
The bill also would allow the imposition of civil fines for noncompliance with the proposed Act by alternative electric suppliers. The fines would 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 would increase the costs of utility rates for consumers, governmental entities as consumers of energy would be subject to these increases.
Fiscal Analyst: Elizabeth Pratt
Maria TyszkiewiczAnalysis was prepared by nonpartisan Senate staff for use by the Senate in its deliberations and does not constitute an official statement of legislative intent. sb213/0708 |