HOUSE RESEARCH Bill Summary

Transcription

1 HOUSE RESEARCH Bill Summary FILE NUMBER: H. F. 659 DATE: March 22, 2001 Version: First Engrossment Authors: Subject: Wolf and Others Minnesota Energy Security and Reliability Act Analyst: Mike Bull, This publication can be made available in alternative formats upon request. Please call (voice); or the Minnesota State Relay Service at (TTY) for assistance. Summaries are also available on our website at: Overview This legislation establishes the twin goals of energy security and reliability as fundamental goals of Minnesota's energy and utility policy. Energy security is defined as "ensuring that the state's energy sources are: (1) diverse; (2) to the extent feasible, produced in the state; (3) environmentally sustainable; (4) available to consumers at affordable and stable rates or prices; and (5) above all, reliable." Reliability is defined as ensuring that adequate resources and infrastructure are in place, and are planned for, to ensure that energy services to Minnesota consumers remains dependable, efficient and secure. To accomplish these goals, the legislation re-engineers the way that infrastructure is planned for in Minnesota, allowing public participation in utility planning procedures as early as possible and requiring the state to conduct both long term comprehensive statewide resource planning (the "energy security blueprint"), and planning for shorter term infrastructure needs (the state reliability plan). In addition, the process for applying for and receiving infrastructure approvals is revised, to make these processes more targeted and more efficient. For example, technical review of infrastructure proposals are consolidated into a single entity, instead of conducted by three different agencies as is currently the case. Incentives for conservation and renewable energy are provided for, as well as for high efficiency, low emission distributed generation resources, such as fuel cells and micro-turbines. The legislation contains the following 6 articles: Article 1 - Planning Independent reliability administratoradministrator State reliability planplan Existing energy facilities

2 Energy security and reliability Energy security blueprint Regional infrastructure planning groups Article 2 - Essential energy infrastructure Power plant siting act rewrite Certificate of need reform Distributed generation tarifftariff Article 3 - Regulatory flexibility Long term contractingcontracting 5 MW customer supply election, if no harm to other customerscustomers Renewable energy rate optionsoptions Conservation investment programprogram Utility joint venturesventures Conservation evaluation by municipal and cooperative utilitiesutilities Article 4 - Interconnection of distributed resources Article 5 - Conforming amendments Article 6 - Miscellaneous provisions Chair of the PUC dutiesduties PUC authority over preventative maintenancemaintenance Cold weather disconnection requirements and other customer protectionsprotections Article 7 - Safety and Service Standards Reporting on outages, interruptions and other reliability incidentsincidents Establishes a benchmark of performance for each utility with over 6,0006,000 retail customers Standards for safety, reliability and service quality for distribution utilities;utilities; must treat similarly situated distribution systems similarly, and recognize differing characteristics of system design and hardware Article 1 - Energy Planning 1 Title. Specifies that this act shall be known as the Energy Security and Reliability Act. 2 Independent reliability administrator. Amendments were made to this section: (1) to make the administrator more directly accountable to the commissioner; (2) to integrate the administrator more tightly into the current processes; (3) to ensure that the budget of the administrator would have no impact on the general fund; and (4) to make the administrator potentially less costly. Establishes an independent reliability administrator to "increase state agency technical expertise and understanding of reliability needs, and increase public confidence in infrastructure projects." The reliability administrator would not be a decision or policy maker. It would perform three functions: (1) consolidate technical review of proposed infrastructure projects in one entity - technical review is currently being done by 3 separate agencies (the department of commerce, the public utilities commission and the EQB) (2) host public meetings around the state to present independent, factual, expert technical information on infrastructure proposals to affected citizens; and (3) develop and present to the commissioner: (i) in each odd-numbered year, a state reliability plan to the commissioner, who in turn will propose a plan to the public utilities commission (PUC) for approval, consisting of critical transmission system upgrades and new transmission projects of 115 kilovolts or more; and

3 (ii) in each odd-numbered year, a report to the commissioner, with copies to the PUC and House and Senate chairs on the status of the reliability of electric service in the state, and make recommendations for regulatory or legislative action. The administrator would be supervised and jointly appointed for a coterminous with the governor by the commissioner of commerce, and confirmed by the public utilities commission. Administrative costs of the administrator would be billed to utilities directly up to $2 million for each fiscal biennium (no impact on the general fund). Authorizes additional assessments if necessary and approved by the commissioner of commerce and the chair of the PUC. Requires a report to the House and Senate finance chairs in any year additional assessments are made. 3 State reliability plan. Amendments were made to this section to integrate this reliability plan into the energy security blueprint. Requires the independent reliability administrator, by January 1, of each odd-numbered year, to develop recommendations regarding critical transmission system upgrades and new transmission projects of 115 kilovolts or more to the commissioner. The commissioner, within 30 days, will propose a state reliability plan, to the PUC. Specifies that only projects that meet the criteria for issuing certificates of need and public purpose designations for large energy facilities may be included in the reliability plan. Requires the administrator to take into account: the most recent state energy plan; the most recent regional energy infrastructure reports; any transmission plan issued by Mid-Continent Area Power Pool, Midwest Independent System Operator or similar entity; any deficiencies noticed under section 216B.019, subdivision 5; any transmission plan developed and proposed jointly by the transmission-owning or transmission-operating entities in the state; the needs of the transmission-dependent utilities in the state; and any other information deemed necessary or reasonable by the administrator. Requires each energy utility, energy service supplier or transmission owner or operator to comply with all requests for information that administrator deems necessary to complete the proposed plan. Requires the commission to ensure compliance with this requirement. Requires the commission to adopt the plan within 180 days. Requires the administrator to hold public meetings in all areas of the state affected by the plan. Specifies that each transmission project on an approved state reliability plan is exempt from additional commission review under section 216B.243 (Certificate of Need). 4 Existing generation facilities. Establishes that it is the policy of the state that existing baseload generation facilities be maintained and upgraded consistent with energy policy goals established pursuant to this chapter. Directs the commission, the department of commerce and other state agencies with regulatory jurisdiction over the operation of these facilities to "take all steps necessary" to incorporate this state policy in their regulatory decisions. 5 Energy security and reliability. Provides that it is a fundamental goal of the state's energy and utility policy that state policymakers maximize the state's energy security. Defines energy security as "ensuring that the state's energy sources are: (1) diverse, including traditional sources, such as coal, natural gas, waste-to-energy and nuclear facilities; renewable sources, such as wind, biomass, and agricultural waste generation; and high efficiency, low emissions distributed generation sources, such as fuel cells and microturbines;

4 (2) to the extent feasible, produced in the state; (3) environmentally sustainable; (4) available to consumers at affordable and stable rates or prices; and (5) above all, reliable." Reliability is defined as ensuring that adequate resources and infrastructure are in place, and are planned for, to ensure that energy services to Minnesota consumers remains dependable, efficient and secure. 6 Energy security blueprint. Requires the commissioner to issue a draft energy security blueprint by March 1, 2002 and every 4 years thereafter. 7 Energy security blueprint contents. Specifies the contents of the energy security blueprint, including: the amount and type of projected statewide energy consumption over the next ten years; a determination of whether and the extent to which existing and anticipated energy production and transportation facilities will or will not be able to supply needed energy; a determination of the potential for conservation to meet some or all of the projected need for energy; an assessment of the environmental impact of projected energy consumption over the next 10 years prepared by the commissioner of the pollution control agency; and benchmarks to measure and monitor supply adequacy and infrastructure capacity,capacity, and to assess the overall reliability of the state's electric system. 8 Energy goals. Requires the blueprint to establish statewide goals and strategies for: energy conservation limiting adverse environmental emissions from electric generation renewable energy production distributed generation (small generation facilities built close to where the electricity is used) affordable and available energy service minimizing the imposition of social costs on energy consumers through energy ratesrates or prices; and increasing the efficiency of the regulatory infrastructure and reducing regulatory andand administrative costs. 9 Blueprint development. Subd. 1. Public participation. Requires the commissioner to invite public comment and participation during the development of the blueprint and to hold public meetings around the state. Subd. 2. Notice and comment; blueprint issuance. Requires the commissioner to provide notice of all public meetings to discuss the proposed blueprint, and allow opportunity for written comment prior to issuing the final blueprint. Requires the commissioner to issue the final blueprint within 4 months of issuing the draft blueprint. 10 Regional energy infrastructure planning. Subd. 1. Establishment. Requires the commission to establish geographic regional energy infrastructure planning regions by August 1, Subd. 2. Planning group. Requires each energy utility that operates in an identified region to participate in the regional energy infrastructure planning group for that region. Requires each

5 group to include as voting members an equal number of representatives of utilities and representatives from each county included in the identified region, appointed by the county boards. Subd. 3. Public meetings. Requires the group to hold public meetings on a regular basis. Subd. 4. Report. Requires each planning group to issue a report to the commissioner and the administrator by December 31, 2001, and every two years thereafter: identifying inadequacies and deficiencies in electric generation and transmission in the region; listing alternative ways to address those inadequacies; recommends alternatives to address identified inadequacies and deficiencies that ensure the reliability and security of the energy system in the region, while minimizing environmental and social impacts; and identifying critical needs. "Critical needs" are defined as those projects that are necessary to maintain reliable electric service to Minnesota consumers that meet or exceed the most stringent state or regional reliability standards. Subd. 5. Deficiencies. Requires an electric that identifies a deficiency in its system to give notice of the deficiency within 90 days to the members of affected regional energy infrastructure planning groups, officials of potentially affected local governments, the commissioner and the administrator. Defines deficiency as "a condition, or set of conditions, that materially limit the adequacy of electric supply, efficiency of electric service, or reliability of electric service to an electric utility's customers in the state that may require construction of a generation or transmission project." Article 2 - Essential Energy Infrastructure 1 Commissioner to issue air permits. Delegates authority from the PCA board to the PCA commissioner to issue air permits for generation facilities. 2 High voltage transmission line. Puts the routing of transmission lines between 100 and 200 kilovolts under the siting/routing authority of an affected county unless the county requests the Environmental Quality Board (EQB) to site the proposed facility. The EQB has the authority to site and route certain large energy facilities, such as high voltage transmission lines. This authority preempts local zoning authority, allowing a utility proposing to build a high voltage power line crossing multiple jurisdictions to only have to receive the approval of a single state siting authority rather than multiple local authorities. Current law specifies that any line under 200 kilovolts must receive routing approvals from all the affected local zoning authorities. In the past, lines smaller than 200 kilovolts were not all that controversial, as a general rule. However, that has been changing, and utilities report that it has become difficult to site even these smaller lines. This provision is intended to make it easier to build these smaller transmission projects. This law change does not apply to any transmission project between 115 kilovolts and 200 kilovolts which is currently pending before a local government unit for approval, such as Xcel's proposal to construct a 115 kv line in Chisago County, over the St. Croix into Wisconsin. In addition, an Environmental Assessment Worksheet (EAW) is often required on lines between 100 kv and 200 kv. Although the EQB does not presently have permitting authority over these size lines, the EQB is the agency that prepares the EAW when one is required. Granting EQB

6 authority over these lines is intended to speed up the review process, so the EQB not only completes the environmental review, but issues the permit as well. It is likely that a number of projects in this size range (100 kv to 200 kv) will be proposed over the next few years. State jurisdiction is intended to expedite review of these projects. 3 Interstate routes. Provides that either issuance of a certificate of need or placement on the public purpose list under section 216E.08 is required before a route permit can be issued for an interstate transmission line. The EQB reports that without a need decision on an interstate line, the siting process is both contentious and extensive. This language would recognize that the public must have been given an opportunity to be heard and to participate in a process to determine why a particular interstate transmission line is needed, before a decision on a specific route can be made by the EQB. & 55 Siting and route permits. Cleans up current language to eliminate references to the "inventory" process. Back in the 1970's there was some idea that the EQB would actually create an inventory of possible study areas for sites and routes, but that approach did not prove to be useful. The EQB will continue to have authority to establish criteria and standards for siting power plants and transmission lines. Generally, how the process will work is that an applicant submits an application identifying at least two proposed sites or routes (unchanged from current law). The EQB prepares the environmental review document. The EQB holds a public hearing on the proposed project before an Administrative Law Judge (unchanged from current law). Following the ALJ process, the EQB applies the criteria and standards applicable to such projects and decides whether to issue a site or route permit and attaches appropriate conditions to the permit (unchanged from current law). Under current law, the process can take up to one year, with a possible six-month extension. This proposal reduces the time extension to 3 months, and only with consent of the parties. Amends current law to allow for a local siting option for generation facilities, upon substantially similar terms, conditions, procedures and standards imposed by the EQB. 6 Application for site or route permit. Clarifies that what initiates the beginning of the time period for a decision from the EQB on the proposal is the acceptance of the application by the chair of the EQB. The normal practice in power plant siting is for an applicant to submit a draft permit to the EQB staff for review, the staff provides comments to the applicant, and the applicant then revises the application. An application may go through one or more revisions before it is complete and accepted by the EQB. 7 Notice of application. Adds a requirement to notify directly property owners adjacent to a proposed site or along a proposed route. The EQB reports that its experience has been that property owners often object when they do not hear about a proposed project until notice of a public meeting or public hearing is published in the paper. This notice requirement will help to ensure that property owners are notified about a proposed project at a very early stage of the proceedings. 8 Environmental review. Provides that an environmental impact statement (EIS) must be prepared on each proposed project under the full siting process. Presently the environmental document prepared as part of the siting process is called an Environmental Impact Assessment. An EIA is essentially the same as an EIS, so this change will simply recognize that the documents are the same. A provision has been included in this subdivision to proclude consideration of the "no-build" alternative in preparing the EIS when a certificate of need has been issued or the project has been placed on the public purpose list. This change allows the EQB to focus on evaluating and mitigating environmental impacts, rather than on the need for the project, which should be addressed in the other proceeding.

7 9 Public hearing. Continues the current requirement that a proposal be given a public hearing before an administrative law judge to develop the factual record upon which the EQB is to render its decision on the application. Part of the hearing must be held in the area of the state where the proposed facility is to be constructed. 10 Technical amendment. 11 Timing. Requires the board to make a final decision on the application within 60 days of receiving the ALJ report, and within one year of the chair's determination that the application submitted was complete. Current law allows an additional time extension of 6 more months. This section allows a time extension of 3 months for good cause and with the consent of the parties. 12 Final decision. Specifies that the board shall issue notice of its decision in the state register within 30 days of its final decision on the application. As with current law, if the project is not environmentally sound and does not meet the criteria and standards for such projects, the EQB will be required to deny the permit. Authorizes the EQB to condition the permit to address any concerns that are identified. 13 Alternative review of applications. Establishes an alternative for certain projects to the full review process described in sections 6 to 15. Replaces the current "exemption" process. Under current law, an applicant could propose to have certain projects exempted from the siting/routing process. Upon receiving an exemption after a rigorous review by the EQB, the applicant would then have to submit its project to review by local officials. If the exemption was denied, the applicant would have to resubmit the application to the EQB for a full review. The main change is that projects will no longer be exempt from the requirement to get a permit from the EQB; all projects within the EQB's jurisdiction will require a permit from the EQB and will not require local approval. Subd. 1. Alternative review. Authorizes an applicant proposing a project that fits within one of the eligible categories to petition the board for an expedited siting process, which the board shall grant within 30 days, unless the board finds good cause for denial. Subd. 2. Applicable projects. Sets forth seven categories of projects for which the applicant may elect to follow the alternative process. (1) small power plants - any power plant between 50 megawatts and 80 megawatts, regardless of fuel type, fall within this category. These are the present cutoff points for an exemption under current law; (2) natural gas fired power plants - these projects are generally non-controversial; (3) retrofitting existing power plants - this language is from current law; (4) a natural gas peaking/storage facility; lower voltage transmission lines - this category (100 kv to 200 kv transmissiontransmission lines) would include those transmission lines that are presently not within the EQB's jurisdiction; (6) short transmission lines (less than 5 miles) - this category is intended to cover those transmission lines of very short distance (a few hundred feet in many instances) connecting new power plants or new substations to existing transmission lines; and existing rights-of-way - this category would include new lines along existing highhigh voltage transmission rights-of-way. Subds. 3 to 7. Procedures. Establishes the procedural requirements for projects under this alternative review process. One major change from the full process is that no EIS is required; a modified environmental assessment worksheet is required instead. This EAW differs from other

8 EAWs in the sense that alternatives and mitigation must still be evaluated. The reason for this change is that while a full EIS may not be required on the kind of projects identified in this category, the public still wants to know about the possibility of alternatives and mitigation. An EAW on other types of projects, like golf courses, does not investigate alternatives and mitigation. An EAW on a power plant or transmission line would contain such information, albeit less than that found in an EIS. Normally, under the environmental review program, an EAW is prepared to determine whether a full-blown EIS should be prepared. That is another change in the draft language. Once an EAW is prepared on the category of projects subject to this alternative review process, no other state environmental review documents are required. No EIS would be prepared on these projects. Another difference is that a contested case hearing before an administrative law judge is not required on these projects. Instead, a public meeting conducted by the EQB is sufficient. However the public is still given an opportunity to present comments and ask questions at the meeting, and the applicant is still required to create an evidentiary record that supports the issuance of the permit. Subdivision 7 provides that a decision on a site permit or a route permit shall be made within six months after an application is accepted by the chair of the EQB as complete. This is half the time allowed for the full siting process. As with the full siting process, the time period commences when the chair of the EQB finds that the application is complete. Importantly, the test for whether a site permit or route permit should be issued at the end of the process is the same under both the full process and the alternative process. If the project is not environmentally sound and does not meet the criteria and standards for such projects, the EQB will be required to deny the permit. The EQB can, however, under both processes condition the permit to address any concerns that are identified. Also, it is important to note that alternatives can be considered under both processes. The time for decision may be extended by 45 days for good cause and with the agreement of the parties. - Emergency permit; annual hearing; public meetings. Retains existing requirements Local planning commissions. Amends EQB procedures to require the board to work with local planning commissions in siting facilities. 18 Distributed generation tariff. Requires each public utility providing electric service at retail to file a distributed generation tariff for commission approval or approval with modification, in order to facilitate and encourage the use of distributed generation. 19 Large energy facility; definition. Amends the definition of a large energy facility (those facilities that must receive certificate of need (CON) approval from the PUC) to exclude smaller generation facilities and to include smaller transmission lines. 20 Modifying existing large energy facilities. Exempts projects to refurbish or upgrade existing large energy facilities from CON requirements, unless the changes lead to a capacity increase at a generation facility of more than 100 megawatts (or 10 percent of existing capacity, whichever is greater), or operation of a transmission line at more than 50 percent of its existing voltage. 21 Merchant facilities excluded from CON. Excludes so-called "merchant facilities" (defined as a generation facility or natural gas peaking/storage facility not-owned by a utility and that is not included in a utility's rate base from the CON requirement. The original purpose for the CON requirement was to ensure that a utility's ratepayers were not

9 asked to pay for investment in new facilities that were not needed by the utility to serve its customers. The risk that a merchant facility is not needed is born by the investors in the facility, not by utility ratepayers. 22 Public purpose designation. Authorizes an applicant for a certificate of need to also petition the commission to designate the proposed large energy facility a public purpose project. The commission shall approve or reject the petition at the same time the commission renders its decision on the certificate of need. Eminent domain authority may only be used in constructing a large energy facility if the commission designates the facility a public purpose project. In designating a facility a public purpose project, the commission must consider whether the facility: remedies a condition, or set of conditions, that materially limit the adequacy ofof electric supply, efficiency of electric service, or reliability of electric service to Minnesota consumers; was identified as a critical need by the relevant regional energy infrastructureinfrastructure planning group; is consistent with all relevant state goals and strategies approved by thethe legislature under section 216B.017; and is otherwise in the public interest.interest. 23 Showing required for a CON. Amends the requirements for what a utility must demonstrate before being granted a CON. The new requirements would be: the accuracy of the long-range energy demand forecasts on which the necessitynecessity for the facility is based; (2) the relationship of the proposed facility to overall state and regional energy needs environmental and socioeconomic benefits of this facility, including its uses toto protect or enhance environmental quality, to increase reliability of energy supply in Minnesota and the region, and induce future development; (4) possible alternatives for satisfying the energy demand or transmission needs including but not limited to potential for increased efficiency and upgrading of existing energy generation and transmission facilities, load management programs, and distributed generation; (5) the policies, rules, and regulations of other state and federal agencies and local governments; (6) feasible energy conservation improvements, required under section 216B.241, sections 216C.05 to 216C.30, or other available conservation programs that can (i) reasonably replace a significant part or all of the energy to be provided by the proposed facility, and (ii) compete with it economically and in terms of reliability; and (7) whether the proposed large energy facility was recommended for construction by the relevant regional energy infrastructure planning group. 24 Joint hearing. Authorizes the commission and the EQB to hold a joint hearing on the siting and need determination for a project, if both bodies find a joint hearing is feasible, more efficient, and may further the public interest. 25 Technical amendment. 26 Repealer. Repeals certain provisions of the power plant siting act. 27 Effective dates. Specifies that provisions relating to the independent reliability administrator are effective July 1, Also, specifies that section 2 does not apply to any transmission project between 115 kilovolts and 200 kilovolts which is currently pending before a local

10 government unit for approval, such as Xcel's proposal to construct a 115 kv line in Chisago County, over the St. Croix into Wisconsin. Specifies that the rest of article 1 would be effective the day following final enactment. Article 3 - Regulatory Efficiency 1 Long term contracts. Requires the commission to allow and encourage a utility to have a combination of measures to manage price volatility and risk, including an appropriate share of long and medium term contracts, in order to minimize consumer exposure to fuel price volatility. 2 Renewable and high efficiency energy rate options. Requires each public utility, municipal utility and cooperative association to offer one or more options that allow a customer to determine that a certain amount of the electricity provided to the customer is from a renewable or high efficiency/low emissions source. Requires these rate options to reflect the utility's costs of acquiring the energy for the customer and that sufficient lead time is given to arrange acquisition of the energy. Also, allows the commission to establish a program for tradeable credits to make acquisition of renewable energy easier for utilities. 3 Agricultural energy projects and customer load management. For those utilities that elect to be governed by the provision of the new CIP program, allows those utilities to spend the incremental difference on grants for agricultural energy projects as well as on projects that increase a customer's ability to control the amount and scheduling of energy the customer purchases from a utility, resulting in an overall decrease in energy consumption. 4 Large customer opt-out. Current law, passed in 1999, allows a large electric or natural gas customer with a load of 20 megawatts or more to petition the commissioner to opt-out of contributing to its utility's conservation improvement program, by demonstrating that the customer is subject to competitive or economic pressures and that the customer has made reasonable efforts to implement cost-effective improvements in the customer's operations. This provision transfers the authority to grant opt-outs to the commission, and allows customers between 10 megawatts and 20 megawatts to petition the commission to also opt-out. The commission may grant a partial opt-out. In addition, this section requires requires a showing by the customer that it has implemented all energy conservation improvements with a 7 year or less payback (to be verified by a registered engineer) prior to be allowed to opt-out of CIP. 5 Municipal and cooperative utilities. Amends the application of the section, so that CIP requirements apply to distribution cooperatives, rather than the G&T's. Reduces the amount that a dollar spent on load management activities counts toward the utility's CIP spending requirement to $0.25 cents by Traditional CIP; transfer. Transfers authority over traditional CIP from the department to the PUC. 7 Energy conservation account. Technical change to eliminate reference to a CIP option that is never used. 8 Overview; independent audit. For those facilities that elect to be governed by the new CIP section, requires filing of an overview of prospective conservation programs, as well as a periodic independent audit of utility conservation programs, by the department or by an entity approved by the PUC, for effectiveness and adherence to program goals and requirements. Allows each utility to dedicate up to 5 percent of their CIP obligation for program monitoring, research, testing and evaluation. 9 Additional conservation spending. Specifies that nothing in this section or the new CIP section prohibits a utility from spending more on conservation than is required in those sections. Also, allows the PUC to order additional CIP spending from public utilities under certain

11 limited circumstances. 10 Conservation investment program. Authorizes each utility that agrees to commit to spending a higher percentage of their gross revenues to conservation initiatives in exchange for an exemption from the regulatory pre-approval process and authorization to use CIP dollars on a broader array of initiatives. Utilities under this program are subject to the audit requirements of section Supply election; no harm to other customers. Authorizes the PUC (or governing body of a municipal or cooperative utility) to allow a customer with a connected load of 5 megawatts or more to choose an electricity supplier other than their utility if the commission or governing body if the commission or governing body makes a specific finding that there is clear and convincing evidence that doing so would not increase costs for, or otherwise harm, any of the customers of the utility currently serving the customer, or in the case of a municipal power agency or a generation and transmission cooperative electric association, any of the customers of a member utility. Requires the commission or governing body to impose all terms and conditions on the approval that are necessary to protect consumers, utilities and utility systems. Current law authorizes customers with a connected load of 2 megawatts or more located outside a municipality to make a similar showing and be allowed to choose an alternate supplier. 12 Utility joint ventures. Authorizes rural electric cooperatives, municipal utilities and investorowned utilities to form joint ventures for the provision of utility services. Patterned after legislation that passed in 1996 and 1997 authorizing joint ventures between cooperative and municipal utilities. 13 Conservation evaluation. Requires municipal and cooperative utilities to evaluate their conservation programs and report to the legislature by February Article 4 - Interconnection of Distributed Resources This article provides technical specifications for interconnecting distributed generation resources (small generation facilities installed close to load) to a utility's electric system. The provisions in this article are based on the Texas distributed resources interconnection rule, which is becoming a standard in the midwest. Article 5 - Conforming Amendments This article makes technical amendments to conform other statutory provisions to the changes made in this legislation. Article 6 - Miscellaneous Provisions 1 Chair of the PUC; expanded duties. Expands the duties of the chair of the commission. & 33 Cold weather disconnection requirements. Clarifies the state's cold-weather disconnection requirements. 4 Customer protections. Requires utilities to offer budget billing plans. Requires a utility to offer payment agreements to customers, unless the customer has the financial resources to make full payment. Provides additional disconnection protections for consumers that have medically necessary equipment in their home. 5 Preventative maintenance. Authorizes the commission to ensure that public utilities are making adequate investment in plants and other facilities used in the production, transmission or distribution of electricity, and are conducting preventive maintenance with respect to those plants and facilities. 6 Wind energy conversion facility; production incentive; limitation.

12 Specifies that, beginning July 1, 2001, a qualified wind energy conversion facility under section 216C.41 (production incentive) may not be located within five miles of another qualified wind energy conversion facility constructed within the same calendar year and owned by the same person. 7 Wind energy conversion systems; production incentive; ownership and cure for default. Specifies that a wind energy conversion facility qualifies for the production incentive if it is owned at least 51 percent by one or more of any combination of the entities listed in section 216C.41. Also specifies that if: (1) the owner of the facility is in default of a lending agreement and the lender takes possession of and operates the facility and makes reasonable efforts to transfer ownership of the facility to an entity other than the lender, the lender may continue to receive the incentive payment for electricity generated and sold by the facility for a period not to exceed 18 months; and (2) if a qualified facility loses the right to receive the incentive because of changes in ownership, the facility may regain the right to receive the incentive upon cure of the ownership structure that resulted in the loss of eligibility and may reapply for the incentive, but in no case may the payment period be extended beyond the original ten-year limit. 8 Repealer. Repeals the requirement for individual utility's to prepare and file integrated resource plans, and the requirement for the department to prepare and publish the quadrennial "energy conservation and policy report." 9 Effective dates. Specifies that articles 2 to 6 are effective on the day following final enactment. to 77 Article 7 - Safety and Service Standards Safety and service standards. Requires reporting on outages, interruptions and other reliability incidents. Establishes performance benchmarks for each utility with over 6,000 retail customers. Requires the commission to adopt standards for safety, reliability and service quality for distribution utilities and to annually report on the aggregate performance of the state's distribution utilities. Requires the performance standards to treat similarly situated distribution systems similarly, and recognize differing characteristics of system design and hardware.