ELECTRIC/GAS ENERGY REVISIONS

House Bill 4298 (reported from committee as H-9)

Sponsor:  Rep. Aric Nesbitt

Committee:  Energy Policy

Complete to 11-30-15

BRIEF SUMMARY:

House Bill 4298 would, among other things, amend the Michigan Public Service Commission Enabling Act to do the following:

§  Retain the current level of retail open access/customer choice but:

o   Require a customer on the waiting list for service from an alternative energy supplier (AES) to wait an additional 20 years if the customer turns down the option when offered.

o   Require written notice of an AES customer's desire to return to an electric utility; under certain situations, require the returning customer to bear any additional costs of the utility for providing that service; and require the customer to stay with the utility for either 15 or 20 years, as applicable, before eligibility to switch back to an AES.

·         Add a new section that requires the establishment of statewide modeling assumptions for integrated resource plans (IRP).

·         Require MPSC to approve an IRP that is the most reasonable and prudent plan to balance certain specified conditions, one condition of which includes as a goal that not less than 30 percent of electric energy needs would be met through a combination of energy waste reduction and renewable energy by 2025.

·         Allow the use of incentives to spur waste reduction programs by utilities to help customers save energy.

·         Require five-year resource adequacy assessments by electric providers regarding expected peak demand, reserve margins, and capacity.

·         Allow three-year contracts for meeting projected capacity needs.

·         Increase the membership of the MPSC by two, and require one commissioner to be a member of the general public.

§  Allow gas utilities with fewer than one million customers to seek partial and immediate rate relief.

§  Sunset the "file and use" provision that enables a utility to self-implement rate changes if the MPSC does not respond to a petition within 180 days, and the current method for a utility to refund overcharges to customers resulting from self-implementation.

§  Require a refund of any electric or gas overcharges caused for any reason to be returned to the customer with interest, but provide the refunds only to industrial customers.

§  Reduce, from 12 months to 10 months, the time period for the PSC to reach a final decision on a rate change request and also for the PSC to consider an amended petition.

§  Lower the threshold from $500 million to $100 million for projects by electric utilities that trigger an application for a certificate of necessity (CON).

§  Ensure that all customers of an electric utility have access to affordable, reliable, and safe utility service from an alternative source before the utility is allowed to discontinue service to those customers.

§  Allow energy optimization programs or cost-based rates for K-12 schools, community colleges, and universities designed to achieve electricity cost savings.

§  Allow review by the Court of Appeals of an MPSC order approving an IRP regarding conformity with the state and US Constitutions and state and federal laws.

§  Revise the act's title to prescribe the power and duties of certain state agencies.

DETAILED SUMMARY OF HOUSE BILL 4298:

House Bill 4298 amends the Michigan Public Service Commission Enabling Act, Public Act 3 of 1939 (MCL 460.1 et al.).  The bill takes effect 90 days after enactment.

Title

The title of a statute gives a brief summary of the matters with which the statute deals.  House Bill 4298 amends the title of the act to eliminate providing "for a restructuring of the manner in which energy is provided in the state" and adds that the act prescribes the power and duties of certain state agencies.

Section 1–MPSC

The bill specifies that the Michigan Public Service Commission is created in the Department of Licensing and Regulatory Affairs (LARA).  Members would still be appointed by the governor with the advice and consent of the Senate, with not more than two being of the same political party.  However, the bill increases the number of commissioners from three to five. 

Under the bill, at least one commissioner must be a member of the general public who meets the following requirements:

·         Is not, nor has been within the five years preceding the appointment, a member of a governing body of a utility or employed by a utility in a managerial, professional, or consulting capacity; an enterprise or professional practice that received over $1,500 in the year preceding the appointment as a supplier of goods or services to a utility or association representing utilities; or an organization representing employees of a utility, association, enterprise, or professional practice, or an association that represents such an organization.

·         Does not have, or did not have within one year preceding appointment, a financial interest exceeding $1,500 in a utility, an association representing utilities, or an enterprise or professional practice that received over $1,500 in the year preceding the appointment as a supplier of goods or services to a utility or association representing utilities.

·         Is not a member of the immediate family of an individual who would be ineligible under either of the above.

Members currently serve six-year terms and new members with like qualifications are appointed in like manner upon expiration of a term; the bill instead specifies that members would serve terms of six years or until a successor were appointed, whichever is later.  If a vacancy occurred, the governor would make an appointment for the unexpired term in the same manner as the original appointment.  An obsolete provision pertaining to staggered terms of the initial commissions would be deleted.

Section 6a–Utility Rate Increase/Self-implementation and Refunds

Under the act, a gas or electric utility is prohibited from increasing its rates and charges or altering, changing, or amending any rate or rate schedules which would result in the increase of the cost of its services without first receiving MPSC approval as provided in the act.  (The MPSC does not have jurisdiction over a municipally owned utility.) 

Gas utilities.  After filing a completed application to increase the rates or charges, the bill would allow a gas utility serving fewer than one million Michigan customers to file a motion seeking partial and immediate rate relief.  The utility must provide notice to interested parties within the service area and afford them a reasonable opportunity to present written evidence and written arguments relevant to the motion seeking partial and immediate rate relief; the MPSC must make a finding and enter an order granting or denying the request within 180 days after receiving the motion.  If partial and immediate relief is granted, the MPSC has 12 months to issue an order regarding that application.

Sunset of self-implemented rates.  Under subsection (2) of Section 6a, if the MPSC fails to issue an order within 180 days of a utility filing a complete application requesting a rate change, the utility may implement up to the amount of the proposed annual rate request through equal percentage increases or decreases applied to all base rates.  If the utility's self-implemented rate or charge increase is more than the MPSC approves in its final order, the utility must refund the amount that exceeds the approved amount, with interest, as provided in the act.  The bill applies subsection 2 only to completed applications filed with the MPSC before the bill's effective date, thus, in effect, sunsetting this provision.

New refund process for large energy customers.  For a customer of an electric utility with an average monthly peak demand of 10 megawatts or more, or a customer of a natural gas utility that uses 700,000 decatherms or more of natural gas per year (e.g., industrial customers), the bill requires that the MPSC use a refund process for electric and gas rate overcharges under Section 6a (whatever the cause of the overcharge) that returns to those customers a refund of the amount the customer was overcharged.  The refund would have to include fair and reasonable interest for the period the customer was overcharged.  This refund requirement would not apply to an energy utility organized as a cooperative corporation under Sections 98 to 109 of the Michigan General Corporation Statute (Public Act 109 of 1931). 

Section 6b–Gas Utility Rates Based Upon Cost of Purchased Natural Gas/Refunds

The rates of a gas utility may be based, at least in part, on the cost of gas that is regulated by the Federal Energy Regulatory Commission (FERC).  If the cost of gas payable by the utility is reduced by a final order of FERC, or as a result of a court order regarding a FERC order that had been appealed, the utility must refund to its customers any refund it receives from the reduced costs of the gas.

The bill requires any gas refund to be returned to each customer that uses 700,000 decatherms or more of natural gas per year in the manner and amount that the sums were charged to the customer so as to accurately refund to that customer the amount that customer was overcharged, plus fair and reasonable interest for the period the customer was overcharged.

Section 6s–Electric Generation Facility/CON/Integrated Resource Plan

Under the act, an electric utility that 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 may submit an application to the MPSC seeking a certificate of necessity (CON) for that construction, investment, or purchase if the project costs at least $500 million and a portion of the costs would be allocable to retail customers in Michigan.  The bill would lower the threshold of projects triggering application for a certificate of necessity (CON) to those costing $100 million or more.  The MPSC may implement separate review criteria and approval standards for electric utilities with fewer than one million retail customers seeking a CON for a project costing less than $100 million (lowered from $500 million). 

Currently, a CON is not issued for any environmental upgrades to existing electric generation facilities or for a renewable energy system; the bill eliminates this prohibition. 

The act allows an electric utility submitting an application for a CON to request certain things; for instance, that the price specified in the power purchase agreement will be recovered in rates from the utility's customers.  The bill would also allow an electric utility to request in an application for a CON that any long-term firm natural gas transportation contracts held to transport natural gas supply to a new generation facility will be recovered in rates from the electric utility's customers. 

The act requires the MPSC to specify certain approved costs in a CON; e.g., the price approved for the purchase of power under the terms of the power purchase agreement.  The bill allows the MPSC to authorize a financial incentive that does not exceed the utility's weighted average cost of capital for power purchase agreements that a utility enters into with an entity that is not affiliated with it after the bill's effective date.

Section 6t–(New)–Statewide modeling assumptions for IRPs

When an electric utility requests a CON under Section 6s, the utility must include an integrated resource plan (IRP) according to standards established by the MPSC.  Those standards currently must include:

·         A long-term forecast of the electric utility's load growth under reasonable scenarios.

·         The type of generation technology proposed for the generation facility and the proposed fuel and regulatory costs under reasonable scenarios.

·         Projected energy and capacity purchased or produced by the utility under any renewable portfolio standard.

·         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 electric utility and the projected costs for those programs.

·         An analysis of the availability and costs of other electric resources that could defer, displace, or partially displace the proposed generation facility or purchased power agreement.  This would include additional renewable energy, energy efficiency programs, load management, and demand response beyond the amounts contained in the above provisions.

The bill requires the MPSC to, within 120 days of the bill's effective date and every four years thereafter, establish statewide modeling assumptions for integrated resource plans (IRPs).  A proceeding under this provision would not be a contested case and the determination of the modeling assumptions for IRPs would not be a final order for purposes of judicial review (the determinations would only be subject to judicial review as part of the final MPSC order resulting from consideration of IRPs).

The MPSC, in consultation with the Michigan Agency for Energy and the Department of Environmental Quality, would have to do all of the following in a proceeding under this provision:

·         Provide public notice that modeling assumptions for IRPs will be established and also about any hearing regarding the establishment of the modeling assumptions.

·         Solicit written comments regarding the establishment of the modeling assumptions.

·         Assess the potential for an increase in energy efficiency in the state.  The MPSC could initiate an assessment before commencing a proceeding to establish the modeling assumptions.

·         Identify significant state or federal environmental regulations, laws, or rules and how each would affect electric utilities in the state.

·         Identify, to the extent practicable, any formally proposed state or federal environmental regulation, law, or rule published in the Federal Register or Michigan Register and how it would affect electric utilities in the state.

·         Identify any required resource adequacy reserve margins in areas of the state.

·         Establish the modeling scenarios and assumptions each electric utility should include in developing its IRP as listed in the bill.

·         Allow other state agencies to provide input regarding any other regulatory requirements that should be factored into assumptions.

·         Publish a copy of proposed modeling scenarios and assumptions on the MPSC's website and the Michigan Agency for Energy's website.

·         Before issuing the final modeling scenarios and assumptions, receive written comments and hold hearings to solicit public input regarding the proposed modeling scenarios and assumptions.

The MPSC would have to, not later than 90 days after the completed proceeding described above, issue an order establishing procedures and filing requirements for an IRP that must be filed by each electric utility whose rates are regulated by the MPSC.  Filing deadlines for submission of each utility's initial IRP could be ordered by the MPSC.  The bill specifies information to be included in an IRP; among other things, this includes the electric utility's plans and feasible alternative options for meeting current and future electric energy and capacity needs and applicable planning reserve margins, the projected renewable energy and capacity purchased or produced by the electric utility, and the projected energy efficient program savings under any energy efficiency program requirements and the projected costs for that program.

Transmission owner.  A transmission owner that owns transmission facilities over which networked transmission service is provided under the applicable regional transmission organization (RTO) tariff to the electric utility filing an IRP must be a party to the contested case hearing regarding that plan and must provide information to the MPSC identifying the transmission infrastructure requirements necessary to support the load and generation forecasted in the electric utility's IRP and the available transmission capacity and the cost of additional transmission capacity that could be used to serve retail customers within the electric utility's distribution service plan.  This information must be considered by the MPSC when approving an IRP to determine the transmission infrastructure requirements necessary for an electric utility.

Report by DEQ:  After an IRP is filed, the MPSC must request the DEQ to prepare a report that includes whether the proposed IRP would reasonably be expected to achieve compliance with the regulations, laws, or rules identified above; any potential decrease in emissions of sulfur dioxide, mercury, oxides or nitrogen, and particulate matter that would result if the proposed IRP were adopted; and if the DEQ chooses to do so, any commercially available alternatives the electric utility could deploy to achieve compliance with the identified regulations, laws, or rules and the estimated costs of those alternatives.  The MPSC could take official notice of a DEQ report.  Information provided in the report would be advisory and not binding on future determinations by the DEQ or the MPSC in any proceeding or permitting process.

Approval/denial of IRP; hearing.  Within 270 days after an IRP is filed, the MPSC must issue an order approving, modifying, or denying the plan.  A hearing, as a contested case, must be held, intervention by interested persons must be allowed, and reasonable discovery must be permitted by the MPSC before and during the hearing in order to assist parties and in obtaining evidence concerning the plan.  Confidential business information must be handled in a manner consistent with state law and MPSC rules.  Alternatives proposed by parties must be considered by the MPSC before approving an IRP.

An IRP must be approved if the MPSC determines the plan is the most reasonable and prudent plan to balance all of the following:

·         The ability to maintain or increase electric reliability in Michigan.

·         Reasonable compliance with all applicable state and federal environmental regulations, laws, and rules.

·         Meeting the need for additional generation capacity and electric energy.

·         Determining that the electric generation resource mix proposed in the plan represents a balanced and adaptable resource portfolio that minimizes the impact on customers of fuel supply and fuel price volatility and promotes competitive rates and affordable bills.

·         Providing reasonable progress toward an increase in energy efficiency.  Approved energy efficiency plans may be implemented by an electric utility.

·         Providing reasonable progress toward maintaining renewable energy resources in the state.  As a goal under this provision, not less than 30 percent of electric energy needs would be met through a combination of energy waste reduction and renewable energy by 2025.

Modification of IRP; rejection by utility.  If the MPSC modifies an IRP, an electric utility could reject the proposed modification within 30 days after the MPSC's order.  If no rejection was made within the timeframe, the modified plan would be considered approved.  If the modified IRP was rejected or if the MPSC denied the plan, a new IRP must be filed within 90 days after the utility's rejection or the MPSC's denial.  The MPSC must consider the proposed plan under the procedures established in the bill and the proceeding must be completed within 135 days after the new plan is filed.  An electric utility could also seek amendments to an approved IRP. 

Electric utility with fewer than one million retail customers.  The MPSC could issue an order implementing separate filing requirements, review criteria, and approval standards for an electric utility whose rates are regulated by the MPSC with fewer than one million retail customers.  An electric utility providing electric tariff service to customers in Michigan and at least one other state could design its IRP to cover all its customers on that multistate basis.

Certifying projects and programs; incentives; recoupment of costs.  In approving an IRP, the MPSC must certify projects and programs needed to comply with an approved plan and specified projected costs for those projects and programs.  Under certain conditions, the certified costs for specifically identified projects and programs in an approved plan would be considered reasonable and prudent for cost recovery purposes and the reasonableness and prudence of those costs would not be a contestable issue in subsequent proceedings.

The MPSC could approve capitalization of energy waste reduction or demand response costs or otherwise preapprove the recovery of costs, including a financial incentive, in order to make commensurate the financial incentives for energy waste reduction, demand response, and their alternatives, as well as cost- or benefit-sharing mechanisms to incentivize participation in energy waste reduction or demand response programs.  Specifics as to the total amount of a financial incentive is detailed in the bill.

Upon application by an electric utility in a general rate proceeding, the MPSC must include in the utility's retail rates all reasonable and prudent incurred costs for a project or program approved in an IRP and could not disallow recovery of those costs if the costs do not exceed the costs certified by the MPSC in the IRP.     

If determined to be reasonable and prudent, the MPSC could include the actual costs incurred by the electric utility in the utility's retail rates.  If the actual costs exceed the costs certified by the MPSC, the utility has the burden of proving by a preponderance of the evidence that the costs are reasonable and prudent; any portion of the cost of an investment exceeding 110 percent of the certified costs is presumed to have been incurred due to a lack of prudence.  If the costs were found to be prudently incurred, the MPSC could include any or all of the portion above 110 percent.

Costs incurred as the result of fraud, concealment, gross mismanagement, or lack of quality controls amounting to gross mismanagement would not be considered to be reasonable and prudent.  The MPSC could disallow recovery of such costs and require refunds with interest to ratepayers for costs recovered through the utility's rates and charges.

Funds used during construction.  An electric utility must be allowed to recognize, accrue, and defer the allowance for funds used during construction, and the bill would not prohibit an electric utility from requesting or the MPSC from authorizing in the utility's base rates construction work in progress for capital improvements approved prior to the assets being considered used and useful.

Unfinished projects.  If assumptions underlying an approved IRP materially change, an electric utility may request, or the MPSC may initiate, a proceeding to review whether it is reasonable or prudent to complete an unfinished project or program included in an IRP.  If no longer reasonable and prudent, the MPSC could modify or cancel approval of the project or program and unincurred in the IRP; if MPSC approval is modified or cancelled, reasonable and prudent costs already incurred by an electric utility could not be disallowed.

Annual report.  An electric utility must file reports at least annually to the MPSC regarding the status of any uncompleted projects that have been approved in an IRP, including an update concerning the cost and schedule of those projects.

Section 6u–(New)–Discontinuance of utility service; retire electric generating plant

A covered utility must file an abandonment application with the MPSC before discontinuing utility service to a geographic area it serves and obtain approval after notice and a contested case proceeding.  To approve an application, the MPSC must determine, by clear and convincing evidence, that all affected customers would have access to affordable, reliable, and safe utility service from an alternative source.  An abandonment application would not be needed if the service were being discontinued to a specific parcel or parcels to enable another covered utility to provide service that the other utility is legally permitted to provide.  "Covered utility" would mean any of the following:

·         A cooperative electric utility subject to the MPSC's jurisdiction for its service area, distribution performance standards, and quality of service.

·         A rural gas cooperative.

·         An electric utility, natural gas utility, or steam utility subject to the MPSC's rate-making jurisdiction.

Proposal to retire electric utility plant.  Not less than 30 days after an electric utility files a proposal to retire an electric generating plant with an RTO, the utility must provide the proposal in its entirety to the MPSC.  Not less than 60 days before application to the operating reliability subcommittee of the federal North American Electric Reliability Corporation (NERC) for approval of a proposal to revise an existing load balancing authority, the electric utility must file with the MPSC a full and complete report of the proposed revision and serve a copy of that report on all other electric utilities in the state.

Section 10–Revision of purpose of Customer Choice Act

Currently, Sections 10 through 10bb are known as the Customer Choice and Electricity Reliability Act.  Section 10 prescribes the purposes of the act.  Several of the stated purposes of the act would be deleted:  to ensure all retail customers of electric power have a choice of suppliers; to allow and encourage the MPSC to foster competition in the provision of electric supply and maintain regulation of electric supply for customers who continue to choose supply from incumbent electric utilities; and to encourage the development and construction of merchant plants which will diversify the ownership of electric generation.

Section 10a–Customer choice revisions; resource adequacy assessment  

Electric choice.  The bill retains the provision allowing retail customers of an electric utility or provider to choose an AES.  Also retained is the 10 percent cap on the number of customers of a utility that may receive service from an AES, the procedure to license an AES, the prohibition on cramming and slamming (the practice by which a customer is switched to other suppliers or services billed for which the customer did not provide consent), and the requirement that the PSC establish a code of conduct.  The bill also retains provisions pertaining to a utility offering its customers an appliance service program, the right to obtain self-service power, the right to engage in affiliate wheeling, and the rights of parties to certain contracts between electric utilities and qualifying facilities.  Also retained is a provision ensuring that an electric utility that offered retail open access service from 2002-October 6, 2008 be able to fully recover restructuring costs.

The bill adds numerous provisions regarding electric choice as follows:

·       Requires a customer on a list awaiting retail open access service who chooses not to take service from an alternative electric supplier (AES) when given the option to wait a period of 20 years before being eligible to receive from an AES.

·       Limits the applicability of a provision allowing an Upper Peninsula iron ore mining or processing facility to purchase electricity from an AES regardless of whether the utility has reached its 10 percent cap; under the bill, this would only apply to customers in compliance with the terms of a settlement agreement requiring it to facilitate construction of a new power plant located in the UP.  Such a customer and the AES would not be subject to the modeling assumptions for IRPs under the new Section 6t or any administrative regulations adopted under Section 6t.  MPSC orders establishing rates, terms, and conditions of retail open access service issued before the bill's effective date remain in effect with regard to retail open access under this provision.

·       Provides that AES customers may subsequently provide notice to the electric utility of the desire to receive standard tariff service from the utility, but would be subject to the following:

o  If there is an equivalent amount of load on the list awaiting retail open access service, the customer would be subject to the procedures in place for each electric utility on the bill's effective date that set forth the terms under which a customer receiving service from an AES may return to full service the electric utility.  However, the customer could not switch back to an AES for a period of 15 years.

o  If there is not an equivalent amount of load on the list awaiting retail open access service but the MPSC determines there is adequate capacity to serve that customer, the customer must provide the utility with 180 days' advance written notice of the intent to return to standard tariff service.  However, if the purchase of additional capacity to serve the returning customer would result in additional costs to the existing customers, the additional costs would instead be assigned to the returning customer, and the customer could not switch back to an AES for a period of 15 years.

o  If there is not an equivalent amount of load and there is not adequate capacity available to serve the customer, the customer must provide the electric utility three year's advance written notice of the intent to return to standard tariff service, participate in interruptible tariff service for three years, or participate in another tariff that provides that any incremental costs, including, but not limited to, capacity, energy, ancillary services, distribution services, and transmission service that are associated with the return of the customer will be assigned the returning customer.  A notice of intent to return to the utility for service would be irrevocable and the customer would not be eligible to receive electric supply service from an AES for a period of 20 years after returning to the utility.

·         Provides that a customer electing to leave utility bundled service after the bill's effective date will continue to be charged–for a period of 15 years– for the utility's full generation costs that are included in the utility's base rates and generation capacity costs and other fixed energy generation costs included in surcharges and power supply cost recovery factors, whether or not the costs result from utility ownership of capacity resources or the purchase of capacity resource from a third party or markets.  The MPSC must implement a cost-based rate design in the utility's rate proceedings to allocate generation capacity costs or other fixed energy generation costs to those customers as otherwise charged if it were a bundled customer of the utility. The utility would be responsible for the customer's capacity requirements and must alleviate the AES's responsibility for the customer's capacity requirements under the bill for that 15-year period.

·         In addition to current requirements for licensing as an AES, the MPSC must require that an AES comply with any load limitation imposed under the bill.

Resource adequacy proceeding.  The bill requires the MPSC to begin a resource adequacy proceeding by May 1 of each year, including establishing a planning reserve margin percentage and local reliability need factor for electric providers for the planning year beginning in the next calendar year and for the subsequent four planning years.  This would not be a contested case.  Information and materials submitted by an entity under this provision would be exempt from disclosure under the Freedom of Information Act.  Protective orders must be issued by the MPSC as necessary to protect the information and material, but the MPSC may make public aggregate data that do not identify individual entities.  The MPSC must do all of the following by November 1 of each year in a resource adequacy forecast proceeding:

·         Require all electric providers to file a resource adequacy assessment for the planning year commencing in the next calendar year and for the subsequent four planning year. The assessment must include:

o   The provider's expected peak demand, reserve margin requirements, and local reliability need.

o   The dedicated and firm electric capacity serving the provider's current retail electric customers' forecasted peak demand plus reserve margin for each of the five planning years under review.

o   Any other information the MPSC determines is necessary.

·         Determine whether there will be a projected capacity shortfall in any of the three subsequent resource adequacy planning years.  A shortfall capacity exists if:

o   The MPSC or RTO determines that due to reliance on capacity from certain sources and the forecasted availability of those supplies for serving load, capacity prices for electric customers may increase by 1,000 percent or more.

o   The sum of each provider's local reliability need resources in any planning year is less than the state's or any area within the state's total local clearing requirement.

·         Determine the amount of capacity needed by each electric provider to address its reserve margin requirement and local reliability need in any of the subsequent three planning years.  A provider would only be required to address its local reliability need if a projected capacity shortfall is determined. The bill establishes a methodology to determine the percentage of the resources needed to meet the provider's reserve margin requirement that may be met through resources from outside of the applicable area within the state.

·         Notify an electric provider (other than a municipally owned utility) of a determination made under the above provision regarding the amount of capacity that provider must obtain within 210 days after receiving the notice to address any projected capacity shortfall in any of the three subsequent planning years.

Objection to notification of need for additional capacity.  The bill establishes a procedure by which an electric provider who believes that the MPSC determination of needing to obtain additional capacity is in error may file an objection within 15 days after receiving the notice.  A contested case hearing would be commenced but no person other than commission staff could intervene in the proceeding.  A ruling would have to be made within 75 days after the objection was filed and materials submitted under this provision would be exempt from disclosure under FOIA.

Obtaining additional capacity.  The bill establishes a protocol for issuing a request for quotes to receive proposals from potential capacity resource suppliers to address any capacity shortfall, including a shortfall by an AES.  The MPSC must issue protective orders as necessary to protect the information and materials submitted under this provision.

Alternative Electric Suppliers.  The MPSC must authorize an AES to serve the expected peak demand if it is determined that the AES has procured the capacity needed to support its expected reserve margin requirement and meet its local reliability requirement.  If the AES failed to do so within 210 days of receiving the notice regarding the amount of capacity the AES must obtain to address a capacity shortfall, the MPSC must initiate a contested case proceeding to limit the amount of load the AES may serve in the state to, at most, the amount of dedicated and firm capacity the AES has procured to meet the bill's requirements. 

The AES must immediately notify customers that are no longer eligible to be served by the AES or that would be unable to be served in the subsequent three-year period.  Affected customers would have 60 days after the notification to either contract with another AES who had demonstrated sufficient excess capacity resources to meet new reserve margin requirements with a new customer's peak demand included, or the customer may elect to return to utility service at the commencement of the capacity shortfall (subject to any return to service provisions provided by law or MPSC order).  If it is determined in a subsequent resource adequacy proceeding that the AES has obtained additional capacity, the MPSC must modify the amount of load the AES may serve in the state.  All actions by the MPSC regarding limiting the amount of load an AES may serve must be conducted under the Administrative Procedure Act and must be completed within 90 days of initiation.

Three-year contracts.  Nothing in the above provisions regarding resource adequacy shall be interpreted as a requirement for or a prohibition of a three-year contract.

Regulated utilities and projected shortfalls.  If the MPSC determines that a cooperative electric utility subject to its jurisdiction for its service area, distribution performance standards, and quality of service, or an electric utility, has not demonstrated that it has procured the capacity needed to meet the bill's requirements, the MPSC must conduct an investigation to determine how to resolve the capacity shortfall with that utility.

Definitions.  The bill would add numerous definitions.  Definitions include, but are not limited to, the following:   "Customer" would mean the building or facilities served through a single existing electric billing meter and would not mean the person, corporation, partnership, association, governmental body, or other entity owning or having possession of the building or facilities.

"Dedicated and firm electric capacity" means the capacity that is owned or under contract by that electric provider that is eligible to be used to satisfy the planning reserve margin requirement of the RTO operating where the electric provider's load is served or the planning reserve margin determined by the MPSC.

"Local clearing requirement" means the amount of capacity resources in a particular geographic area that must be present to ensure reliability as defined by the RTO operating in the territory where the electric provider's load is served or by the MPSC.  If the RTO did not provide the MPSC with a local clearing requirement for a future planning year, the MPSC must apply the latest local clearing requirement determined by an RTO to that future planning year.

"Local reliability need" means an electric provider's load based pro rata share of the state's, or area within the state's, local clearing requirement.

"Local reliability need resources" means the volume of dedicated and firm electric capacity eligible to meet an electric provider's pro rata share of the state's, or area within this state's, local clearing requirement.

"Planning years" means June 1 through the following May 31 of each year.

"Standard tariff service" means, for each regulated electric utility, the retail rates, terms, and conditions of service approved by the MPSC for service to customers that do not elect to receive generation service from an AES.

Section 10c–Penalties for non-compliance/Slamming/cramming

The bill makes revisions of a technical nature to numerous statutory references.

Section 11–Cost allocation/Energy optimization programs for schools and colleges

Cost allocation.  Currently, the cost of providing service to each customer class is based on the allocation of production-related and transmission costs based on using the 50-25-25 method of cost allocation.  The bill will eliminate the underlined language and instead base the allocation of production-related and transmission costs on a 100 percent demand-related basis using the "four-coincident-peak" allocation methodology.

Energy optimization programs for K-12 and institutions of higher education.  The bill would allow, notwithstanding any law, regulation, or commission order to the contrary, the MPSC to (at the request of an electric utility) develop and implement reasonable energy optimization programs or cost-based rates for public and private schools, universities, and community colleges that are designed to achieve reasonable electricity cost savings for those institutions.  The MPSC must approve all electric utility energy optimization program expenses for those institutions for full recovery through, at an electric utility's sole discretion, the electric utility's general rates, tariffs, or surcharges.  As used in this provision, "energy optimization programs" includes, but is not limited to, demand side management programs.

Miscellaneous.  The bill also eliminates provisions pertaining to proceedings by the MPSC examining cost allocation methods and rate design methods used to set rates; filings by affected utilities modifying the existing cost allocation methods and rate design methods; an interim report by an administrative law judge to the Legislature regarding the cost allocation and rate design proposals; an analysis of affordable rates; and other obsolete provisions.

FISCAL IMPACT:

House Bill 4298 (H-9) would have multiple and varying fiscal impacts on the Public Service Commission (PSC) within the Department of Licensing and Regulatory Affairs (LARA) to the extent that revisions to the composition of the PSC and the regulatory processes pertaining to self-implemented rate proposals; overcharge refund procedures; Certificate of Necessity, Integrated Resource Plan, discontinuing utility service, and resource adequacy proceedings; and electricity choice provisions would alter and effect the PSCs administrative and adjudicative workload. However, due to a lack of detailed accounting information pertaining to the costs associated with various types of regulatory activities undertaken by, and proceedings held before, the PSC, and the relative lack of consistency in the costs associated with any particular activity or proceeding, the fiscal impacts are indeterminate both in direction (positive or negative) and degree (nominal or substantial).

Nonetheless, it is important to note that Section 2 of the Costs of Regulating Public Utilities Act of 1972 stipulates that LARA "shall ascertain the amount of the appropriation attributable to the regulation of public utilities…[which] shall be assessed against the public utilities" according to a statutory formula. Consequently, irrespective of the short-term and long-run fiscal impacts of HB 4298 (H-9), LARA would assess all privately-owned public utilities the amounts sufficient to administer the PSC’s regulatory responsibilities. The average annual amount assessed between FY 2011-12 and FY 2013-14 was $25.8 million.

Additionally, HB 4298 (H-9) would have an indeterminate fiscal impact on the Department of Environmental Quality (DEQ).  It is unclear how many Integrated Resource Plans would be submitted to the DEQ for review. It is also unclear whether plan review would create a substantial additional administrative burden on the DEQ’s existing administrative and compliance structure. The DEQ routinely reviews environmental compliance plans but the projected volume and complexity of the Integrated Resource Plans is unknown. Therefore the fiscal impact on the DEQ is uncertain at this time.

                                                                                        Legislative Analyst:   Susan Stutzky

                                                                                                Fiscal Analyst:   Paul B.A. Holland

                                                                                                                           Austin Scott

This analysis was prepared by nonpartisan House Fiscal Agency staff for use by House members in their deliberations, and does not constitute an official statement of legislative intent.