STAFF REPORT ON ELECTRIC INDUSTRY RESTRUCTURING Staff of the Michigan Public Service Commission December 19,1996 EXECUTIVE SUMMARY On January 8, 1996, Governor John Engler sent to the Public Service Commission a list of recommendations from the Michigan Jobs Commission regarding electric utility reform. The Governor requested that the PSC refine and act upon those recommendations. In 1996, the Commission conducted public hearings on the matter, and Commissioners and Staff have been meeting with a variety of interested parties. This Staff Report is issued as a result of these meetings. It represents the opinion of the Staff and not necessarily that of the Commission. The Report recommends a phased-in program of direct access (also known as customer choice) based on two fundamental principles: (1) all customers should be eligible to participate in the emerging competitive market, and (2) rates should not be increased for any customers and should be reduced where possible. These principles were derived in response to public comment received during the last year. The Report recommends that, beginning in 1997, customers have the opportunity to select the power supplier of their choice. All customers would be eligible to participate, but the total amount would be limited fixed blocks of load equaling approximately 2«% of each utility's load in 1997, 5% in 1998, 7«% in 1999, and 10% in 2000. In 2001, all commercial and industrial customers served at primary voltage would be eligible, and in 2004 all remaining customers would be eligible. The Report also indicates that stranded costs should be limited to five specific cost categories. To avoid subsidization, stranded costs should only be recovered from those customers exercising choice. Moreover, the Report suggests that securitization be used, where possible, as a mechanism for recovery of potentially stranded assets. Securitization (more commonly known as "rate reduction bonds") is a method of refinancing that lowers electric cost to all customers. The Report indicates that through the combination of customer choice and rate reduction bonds, the first few years of savings in electricity costs to Michigan customers could exceed $300 million. Assuming no other changes, this would reduce the average rates for electricity to Michigan residential, commercial and industrial consumers to levels less than the region or the U.S. as a whole. Additional savings could be possible in subsequent years. Finally, Staff believes that the recommendation regarding electric industry restructuring will assure safe and reliable service to customers and financially healthy utilities during the transition period. I. INTRODUCTION On January 8, 1996, Governor John Engler sent to the Public Service Commission a document entitled "A Framework for Electric and Gas Utility Reform" prepared by the Michigan Jobs Commission. That framework contained six recommendations for the near term (by January 1, 1997): (1) allowing direct access for new commercial and industrial load, (2) addressing stranded costs, (3) exploring the replacement of rate of return regulation with rate cap regulation, (4) allowing immediate file and use tariffs, (5) eliminating prescriptive regulatory measures, and (6) reorganizing the Public Service Commission. The framework also recommended creating an independent power pool by January 1, 1998 and allowing direct access for all commercial and industrial customers by January 1, 2001. The Governor indicated that he was "confident that [the Public Service Commission] will work to refine and act upon the enclosed blueprint for competition in a timely manner." On January 17, 1996, the Public Service Commission responded to the Governor, indicating that it embraces the principles for reform that animate the plan and that the Commissioners look forward to working with all interested parties to deliver a framework for competition. Since then, the Commission has met informally with numerous interest groups from Michigan. In addition, it directed that applications be filed to implement the first phase of the Jobs Commission recommendations. Furthermore, the Commission held public hearings in Saginaw, Detroit, Southfield, Grand Rapids and Lansing. In addition to formal activities undertaken directly by the Commission, the Commission Staff has been meeting with a variety of interested parties throughout 1996. The specific details in this Report were developed primarily through discussions with Consumers Power Company and Detroit Edison, but also from discussions with many of these other parties. As a result of public input received during this process, the Commission Staff believes that certain refinements to the Framework recommended by the Jobs Commission should be considered. These refinements incorporate two fundamental principles. First, all customers should be eligible to participate in the emerging competitive market. This was a major concern expressed by many groups and individuals. For example, at a public meeting to discuss restructuring hosted by the Commission Staff, a representative of Attorney General Frank J. Kelly noted that under the original Framework, "Michigan's millions of residential and small business ratepayers will have no ability to procure low-cost generation from competitive providers. This is the wrong tack to take." This Staff Report suggests a modified approach designed to significantly increase the ability of all customer classes to participate and share in the benefits of competition. Second, electric restructuring should not result in customer rate increases. In a sense, this is a corollary to the first principle -- a major concern of many has been that a few customers would be eligible for the benefits of competition while the vast majority pay for the associated costs. For example, in Case No. U-11076, the Commission received numerous petitions protesting the possibility of a 30% rate increase for residential customers to fund price reductions for large industrial customers. With the recommendations in this report, taken as a package, residential consumers can be assured that no such rate increase to residential customers will take place. The concepts discussed in this Report are designed to ensure that rates are not increased for any customers as a result of restructuring and, where possible, rates are reduced through the use of rate reduction bonds. The program outlined in this Report is designed to fulfill five objectives. First, it protects the interests of smaller customers, including low income residential customers and senior citizens. Customers who choose not to participate in the competitive supply market will continue to receive service from the local distribution company which will continue to be regulated. Second, the program provides opportunities to strengthen Michigan's business community. The interest in electric restructuring has been primarily motivated by the negative impact high electric rates have in attracting manufacturing facilities to Michigan. Rate reductions resulting from customer choice and from rate reduction bonds should strengthen Michigan's competitive position. Third, the program includes funding for employee retraining to assure that utility employees are not negatively impacted by restructuring. Promoting employee retraining is good public policy, improves the Michigan economy by retaining a well-trained work force, and is consistent with the approach taken in other states. Fourth, the phase-in program provides utilities with the opportunity to prepare for competition so that they remain Michigan-based companies. The ability of local utilities to remain viable and to continue as Michigan job providers was an important element in the initial Framework presented by the Jobs Commission. Fifth, the program is designed to foster competition upon a level playing field. Currently, there is a lack of opportunity for new entrants to the electric supply market. The direct access program provides a market to permit the development of new competitors to serve all classes of customers. The Commission has jurisdiction over all investor electric utilities and rural electric cooperatives in Michigan. Municipal electric utilities are not subject to Commission jurisdiction. Although this Report discusses details regarding Consumers Power and Detroit Edison, its concepts and principles are intended to apply to all jurisdictional electric utilities. . II. DIRECT ACCESS SCHEDULE The Jobs Commission Framework contained a phase-in program, such that new commercial/industrial load would be eligible for direct access in 1997 and existing commercial/industrial customers would be eligible in 2001. This phase-in allowed for a relatively smooth transition to a competitive model, but had the disadvantage of restricting direct access to a limited number of customers. This Report suggests a much more aggressive phase-in program, as follows: * Beginning in 1997, and each year thereafter, each utility would make a block of direct access available to all customers equal to 150 MW for Consumers Power, 225 MW for Detroit Edison, and at least equivalent amounts for other utilities (approximately 2«% of their load). These blocks would be allocated among customers through a bidding process. * In 2001, all commercial and industrial customers served at primary voltage would be eligible for direct access. All other customers would continue to be phased-in proportionally, at the rate of approximately 2«% of that load per year. * In 2004, all remaining customers would be eligible for direct access. * The total amount of load Detroit Edison and Consumers Power Company permitted to go to direct access competitive service in the initial phase-in years of 1997-2001 equals 1500 MW, ten times larger than the amount opened to competition in the retail wheeling experimental program envisioned in Case No. U-10143/U-10176. III. RATE CHANGES The transition to the more competitive electric power market described above will provide direct access customers with the opportunity to choose their electric supplier and thereby potentially reduce their power costs. Customers not participating in the direct access program need to be protected from potential cost increases that might otherwise result from the transition to direct access. Such protection is especially important during the period when direct access opportunities are of necessity limited. There are three methods of providing such protection: (1) base rate freeze, (2) alternative power supply cost recovery treatment, and (3) limited performance based regulation. Use of these three approaches will assure customers that their generation costs will not change beyond already approved levels until the customer has the ability to choose a different generation supplier and will also provide the utility with incentives to control costs associated with the transmission and distribution of power. Rate Freeze During the transition period, the opportunity for direct access should be accompanied by an initial freeze on the base electric rate levels subject to adjustment only if changes in laws, accounting requirements, or government policies significantly impact utility costs. For generation costs, the moratorium should remain effective until a customer class has the option of direct access. The base rate freeze assures non-participants that they will not receive rate increases in order to permit direct access for other customers. Cost increases associated with acquiring additional generating capacity or supply will not be passed on to non-participants during the transition period. Power Supply Cost Recovery Clauses Accompanying the proposed freeze in base rate levels, modifications to the existing power supply cost recovery (PSCR) clauses would provide additional protection for non-participating customers during the transition period. Suspension of the PSCR clause during the transition period will protect non-participants from increases in the price of fuels or purchased power. By working in parallel with the base rate freeze, the suspension of the PSCR clause and establishment of a fixed level of fuel and purchased power expense recovery after hearings and development of a record will protect non-participants from uncertainties arising during the transition to a competitive generation market. In implementing suspension of the PSCR clause, the appropriate fixed level of fuel and purchased power costs to be recovered during the transition period should be determined, so as to recognize utility specific factors or conditions to facilitate the transition to a competitive environment. Performance Based Regulation The generation function performed by existing utilities will become a competitive service with the restructuring of the electric power industry. The base rate freeze and the PSCR suspension previously discussed are designed to protect non-participants from cost increases related to generation during the period when they do not have direct access capability. Unlike generation, which is expected to become competitive, the transmission and distribution functions will likely remain regulated services, for the foreseeable future. The regulated distribution provider will need to maintain and expand its facilities to provide service to existing and future customers. The question is: what regulatory process is appropriate for regulated service providers in the restructured industry? Fundamentally, the regulated distribution utility should be provided with the incentive to perform its functions as efficiently as possible while continuing to maintain system reliability and promote safety. The existing regulatory system may not instill the proper incentives in a future restructured industry and thus it may be appropriate to move away from the cost of service regulatory approach. It appears that a properly designed performance based regulatory (PBR) system provides incentives to the utility while protecting the customer from excessive price increases. A PBR system, limited to the regulated transmission and distribution system, recognizes that the cost of these services can and will vary in the future. By placing a cap on the annual level of cost increases, a PBR system instills in the regulated distribution utility incentives to perform efficiently and cost-effectively. Standards within the PBR system will further ensure that reliability, service quality and safety are not compromised. The establishment of a PBR system for functionally separated and regulated distribution service offers cost tracking and provision of reliability of service advantages over the functionally integrated cost of service rate setting mechanism that has traditionally been used to establish rates. Under the current method, some utility and regulatory capital and maintenance expenditure decisions for the distribution system have historically been affected as much by earnings and rate concerns as by actual quality of service and reliability needs of the distribution systems. For instance, during periods when demand for production related expenditures was high, expenditures for distribution related activities, such as tree trimming or reliability enhancement, have generally been reduced to levelize the demand for overall capital investment to limit the resulting rate impacts related to total capital needs, and to preserve utility earnings. Conversely, during periods of low demand for production investment, expenditures for the distribution system have been generally increased. In most cases, Staff believes that reducing or limiting necessary work on the distribution system for more than a short period of time resulted in a material deficit or work backlog that adversely affected service to some customers. By functionally unbundling production, transmission, and distribution, and the rate setting mechanisms associated with each function, Staff believes that is possible to establish a separate PBR for the transmission and distribution functions that provides timely recovery of necessary expenditures associated with improvements for distribution related activities and concurrently preserves or enhances reliability of service provided to customers. It is important that such a mechanism not focus solely on timely recovery of expenditures or incentives to limit cost, but should also recognize the level of end use service reliability provided to the customer as well. One electric PBR concept that has been before the Commission in a number of forums is a mechanism that indexes agreed to base costs to an inflation index such as the Consumers Price Index (CPI). Staff recognizes that such an approach for electric rate setting has been criticized by some parties in the past. However the previously considered mechanisms were typically designed to adjust rates for total bundled electric service including all costs associated with power supply. To test the feasibility of this concept, Staff indexed changes in historical non-production related annual O&M expenditures and the estimated increases in annual revenue requirement associated with transmission, distribution, and allocated general plant investment for both Consumers Power and Detroit Edison using 1984 as a base year. Using 1984 as a base year, Staff determined that total changes in revenue requirement for both companies generally tracked or exceeded annual changes in the Detroit area CPI for the same period. This suggests that a CPI based mechanism will provide an effective near term alternative to the cost of service mechanism traditionally used to set rates associated with transmission and distribution costs. In recent years, electric utilities and the Commission have collaborated in an effort to improve the reliability of the electric distribution systems within this State. Major weather related events in 1991, had previously exposed significant weaknesses in these systems. Most of the weaknesses have since been eliminated as a result of this collaborative effort. To preserve the reliability gains achieved and to assure that the customer continues to receive quality service, Staff believes that any PBR mechanism to be applied to the transmission and distribution functions also incorporate service standards. A PBR mechanism applied to the transmission and distribution functions will result in a more levelized application of investment for those systems, timely recovery of these expenditures for the utility, and an incentive for the utility to provide acceptable service to all customers. As the above discussion shows, a PBR system restricted to transmission and distribution appears appropriate. Further, use of a CPI methodology which incorporates a productivity offset would appear to be a reasonable proxy for regulation of these costs during the transition period. Staff supports an offset of 1% (CPI-1), comparable to that used in telecommunications rate-setting. The impact of such a mechanism on the retail consumer will be very modest during the transition period. Because the transmission and distribution functions comprise less than « of the total cost of serving customers the impact on customers bills will be less than « of the CPI-1. Thus, with a CPI of 3%, the CPI-1 mechanism applied to transmission and distribution costs would result in a rate adjustment of less than 1% for the year. The CPI-1 mechanism should include performance standards relative to reliability, quality of service and safety to protect customers from service deterioration. The PBR mechanism should be reviewed at five-year intervals to assure that it is functioning properly. Accordingly, the CPI-1 mechanism should remain in effect through the end of 2001. Prior to that date, a comprehensive evaluation should be conducted to determine if it remains an appropriate regulatory approach. IV. TRANSITION COSTS Transition costs (often referred to as stranded costs) are costs of an electric utility consisting of two elements: (1) costs that were incurred during the regulated era that will be above market prices during competition, and (2) costs that are incurred to facilitate the transition from regulated monopoly status to competitive market status. Transition costs include regulatory assets, societal costs (costs incurred for various social programs), restructuring costs (those incurred specifically to allow competition to proceed, such as the cost of creating an independent system operator), and above-market costs of purchased power contracts previously approved by the Commission, and power supply facilities acquired under the "obligation to serve" principle. Stranded cost recovery has been a fundamental component of restructuring programs at both the federal and state level. For example, the Federal Energy Regulatory Commission states that: We reaffirm our preliminary determination that the recovery of legitimate, prudent and verifiable stranded costs should be allowed. Having considered the arguments raised by the commenters that oppose stranded cost recovery, we continue to believe that utilities that entered into contracts to make wholesale requirements sales under an entirely different regulatory regime should have an opportunity to recover stranded costs that occur as a result of customers leaving the utilities' generation systems through Commission -jurisdictional open access tariffs or FPA section 211 orders, in order to reach other power suppliers. As we indicated in the Supplemental Stranded Cost NOPR, we do not believe that utilities that made large capital expenditures or long-term contractual commitments to buy power years ago should now be held responsible for failing to foresee the actions this Commission would take to alter the use of their transmission systems in response to the fundamental changes that are taking place in the industry. (FERC Order No. 888, pages 451-2, footnote omitted) Similarly, states such as California and Pennsylvania have endorsed the concept of transition cost recovery as an essential element of electric industry restructuring. The opportunity to recover transition costs is necessary to assure a fair, smooth, and realizable restructuring of the electric industry. Without reasonable recovery of transition costs, significant adverse and unacceptable impacts on various interested parties will occur. In short reasonable recovery of transition costs helps to assure financially healthy utilities and reliable electric service in the State. Staff believes that transition costs should include the following categories: (1) regulatory assets, (2) nuclear capital costs, (3) contract capacity costs in power purchase agreements, (4) employee related restructuring costs and (5) other costs related to implementing restructuring. First, regulatory assets consist of unrecovered costs of demand side management programs, plant abandonment costs, unfunded pension and health benefit liabilities, deferred tax liabilities, and other similar costs. These costs have been approved by the Commission and collection of these costs have been deferred to future time frames. Second, transition costs include the capital costs of certain existing power supply facilities. Included in this category are the capital costs (net book) of nuclear facilities. Although nuclear power was projected to be the most economic future source of energy to meet the country's need, the projection has not materialized. More stringent governmental standards, and the need to undergo costly retrofits to meet those standards, have led to very high capital costs. The offsetting operating efficiencies have not materialized as expected because of tightened NRC safety requirements. Given the need to ensure adequate financial resources for nuclear plants, the entire net capital cost of the facilities should be included as stranded costs because it is unlikely that the market value of the energy produced will be able to offset the operating and maintenance costs for some time to come, let alone make a contribution towards capital recovery. As a general rule, it is not necessary to recognize capital costs of hydroelectric, coal, oil or gas power production facilities that are owned by the utility because they should be at market value by the end of the transition period, provided that the combination of the performance based regulation and the utility's stranded cost mitigation efforts produces the necessary capital recovery. The third category consists of capacity costs included in long-term power purchase agreements which have been approved by the Commission, less the estimated near term market value of that capacity in an open access environment. The vast majority of these agreements are with "qualifying facilities" (QFs) that are federally mandated under the 1978 Public Utilities Regulatory Policies Act (PURPA). In general, PURPA requires that utilities contract with QFs at the utility's avoided cost at the time of the contract. Those prices are expected to exceed future market prices. The fourth category is employee related restructuring costs. Staff recommends that audited and verified costs incurred to transition the work force as a result of industry restructuring should be included. These costs would not be incurred absent the restructuring. Promoting the retraining of employees, for example, is good public policy, will improve the Michigan economy by retaining a well-trained work-force, and is consistent with the approach taken in other states (e.g. California). The final category includes other costs associated with the restructuring. These include the specific costs of implementing the direct access system, e.g., establishing an independent system operator, creating new billing software systems, new metering systems, etc., as well as other costs associated with the accelerated schedule for direct access implementation. Once transition costs are defined and calculated, there are two possible approaches to recovering them. Where feasible, the preferred alternative would be to securitize the asset and provide a rate reduction for all customers. This option is discussed in detail in Section V. Stranded costs that are not recovered through rate reduction bonds will be recovered through a transition charge billed to direct access customers. The transition charge begins when the customer takes direct access and continues through 2007. Preliminary calculations indicate that for Consumers Power Company and the Detroit Edison Company the sum of the transition charge and the securitization charge (for rate reduction bonds) would be in the range of 1.2› to 1.3› per kwh. This compares to stranded cost charges in other states of 2.8 ›/kwh for Massachusetts Electric Company, 2.8 ›/kwh in Rhode Island, and 4 to 6 ›/kwh for New Hampshire Public Service Company. The stranded cost charges in other states, such as California and Pennsylvania, have yet to be determined. V. RATE REDUCTION BONDS Securitization is one method utilized in other states for dealing with costs that might otherwise be stranded as a result of electric restructuring. Securitization has the dual advantages of funding potential stranded costs while simultaneously reducing customer rates (hence, the name "rate reduction bonds"). Under the securitization option, potentially stranded cost items on the utility's balance sheet (most notably capital costs of nuclear plants and regulatory assets) are refinanced at significantly lower overall cost of capital and the savings are passed on to customers. The methodology is as follows: 1. Legislation is required to establish a trust to issue the bonds and to assure the payment of interest and principal through a non-by passable charge on the delivery of power. 2. Bonds are issued by the trust who delivers the funds to the utility. 3. The funds are used to reduce the amount of debt and equity on the utility's balance sheet. Rates are reduced to reflect the resulting lower financing costs. 4. The utility collects securitization charges from all customers and forwards these to the trust for debt servicing. Securitization results in a reduction in base rates that is partially offset by a charge for bond repayment. The overall impact is a net rate reduction for customers because higher cost financing through a combination of equity and traditional utility bonds (typically rated approximately A to BBB) is replaced by lower cost financing with securitized bonds rated AAA. In other states, securitization has been structured so as not to utilize the bonding authority of the state. The purpose of the legislation is to create a transferrable property right to collateralize the debt. Because securitization reduces rates while mitigating the stranded cost issue, it is being actively considered by a number of states. If the Legislature grants the necessary authorization, Staff recommends that securitization be pursued in those instances where it is cost-effective. Assuming a 15-year bond maturity with an interest rate of 7.5%, preliminary analysis indicates that as of July 1, 1997, securitizing approximately $2 billion of Fermi 2 assets, $400 million of regulatory assets, and $400 million of PA2 of 1989 contract payments achieves a net rate reduction of approximately $295 million ( 9%). Securitization works well for Detroit Edison because it has a large capital investment in a nuclear plant. Consumers Power has two nuclear plants that are nearing the end of their licensed lives and have lower remaining plant balances by comparison. Consequently, it appears that securitization will not achieve results of the same magnitude. Because the potential value of securitization is heavily dependent upon financial considerations specific to each utility, it is clear that it will not be as effective in every instance. Nonetheless, it is clear that securitization has the potential to reduce overall electric rates in Michigan very substantially, and thus is an important element in an overall plan of restructuring. VI . OTHER ISSUES Allocation of Direct Access During the transition period, as the blocks of direct access become available, it may be necessary to allocate the block among customers who desire to participate. Although either first-come-first-served or lottery could be used to allocate the blocks, bidding provides a fairer and more cost-effective method. Under this approach, customers wishing to participate in the blocks would submit a sealed bid indicating an amount they would pay above or below the transition charges. Winning bidders will pay the amount of their bid in addition to other charges until all customers in their class are eligible for direct access. At that time, the bid amount is dropped and they revert to the same rates as other direct access customers. The bid amounts are charged or credited to the utility's transition charge. Larger customers will bid individually under this process. Initially, smaller customers will be required to aggregate their load in order to bid due to existing technology limitations (i.e. small customers do not have demand meters that allow load following). Staff believes that real time metering (and two-way communications or telemetering) will be beneficial in matching, on a timely basis, power supply costs with consumers' buying decisions. Only in that way is the buying decision directly linked to the production decision so as to fully realize the benefits (especially economic management of customer demands) of restructuring of the electric utility industry and moving to a competitive generation sector. It is anticipated that new technology will be developed in response to a market need and that smaller meters of the required type will become available. The primary advantage of bidding is that it allocates direct access to those customers who obtain the most value from it and thus are willing to bid the highest. This benefits all customers since the bid revenues are used to offset the transition charges. Furthermore, allowing negative bids ensures that the block will be fully subscribed. Reciprocity Any power supplier capable of delivering power to the transmission system of the local host utility should be eligible to provide service under the retail direct access program. However, eligibility should be conditioned on the requirement that all originating suppliers in any retail wheeling transaction provide for reciprocal rights to the utility providing that retail direct access service. Reciprocity should be a contractual condition for a supplier to sell power to a customer of a utility. Since Act 69 (MCL 460.501) requires a power seller to obtain a certificate from the Public Service Commission, that would be the appropriate forum to determine whether comparable and reciprocal direct access exists. The reciprocity condition requires that the appropriate party or parties agree to provide to the host utility reciprocal retail direct access to retail customers on terms and conditions which are comparable to those made available by the host utility. This reciprocity condition should apply to all entities engaging in direct sales or delivery of power to the retail direct access customers, and to all affiliates of such entities. The condition should also apply when an intermediary (such as a broker or marketer) participates in such a transaction. In such a case, the operator(s) of the generation source or sources involved in the transaction must satisfy the reciprocity condition. "Comparable" terms are those which provide for retail direct access to an amount of retail customer load which is equivalent to that provided by the host utility, specific rates, terms and conditions for retail direct access service which are equivalent to those offered by the host utility, and which have been approved by all applicable regulatory authorities for use in retail direct access transactions. Stand-by Stand-by is the back-up or alternative power supply for a customer's primary source of power. Historically, customers with on-site generation have been able to contract with and use the local electric utility as their source of stand-by power in the event of failure of their on-site power supply source. With the advent of direct access, stand-by takes on new dimensions. Stand-by for customers using retail direct access service means having alternative sources of power supply in the event of a shutdown of the primary generation source or the inability to transmit the power from a distant supplier. Stand-by is necessary only if a customer wants a service reliability level greater than that provided by his primary source of power supply. If a retail direct access customer desires stand-by service they can acquire it from a number of sources. First, he could acquire stand-by from the local host utility. Second, he could have stand-by generation installed on his premises. Typically, on-site emergency generation is in the form of small diesel generators. Third, he could arrange for stand-by from other power suppliers. They could be other distant power suppliers, or third parties willing to install stand-by electrical capacity on the customer's premises. In summary, customers have choices in stand-by just as they have choices in primary power supplier. It is therefore problematic to say that the local host utility should be required to provide stand-by in a restructured competitive electric industry. The whole movement to direct access is based on the notion of creating a competitive electric generation or power supply market. Current thinking is that a "natural monopoly" for electric generation no longer exists. It is believed that many power suppliers can enter into the market (relatively easily) and competition, not regulation, will work to assure fair and reasonable prices and adequate supplies for the consumers. Extending that underlying principle to the stand-by sector of power supply suggests that it is simply a sector of the new competitive power supply market, and a sector where supply and pricing should be based on the principles of competition (and unregulated). While the local utility could be considered a source of stand-by, other alternatives are clearly available. FERC, in Order 888 dated April 24,1996 made findings along these lines: We accept the term "Backup Supply" as the name for this interconnected operations service, but we will not require this service as an ancillary service under an open access transmission tariff. Backup Supply Service is not required for comparable open access transmission service. Backup Supply Service is an alternative source of generation that a customer can use in the event its primary generation source becomes unavailable for more than a few minutes. Although we believe that the two short term operating reserve services (spinning and supplemental) are necessary to support transmission, we concluded that long-term service is not necessary. Backup Supply is a generation service that may reasonably be viewed as the responsibility of the transmission customer, who may contract for backup service or curtail load. We will impose no obligation on the transmission provider to provide power to the customer for a time longer than specified in the tariff for the customer's own backup power supply to be made available. The transmission provider is obligated to protect against emergencies for a short time; it has no obligation to furnish replacement power on a long-term basis if the customer loses its source of supply. The transmission provider has no obligation to provide power for the weeks necessary for unit maintenance for example. The transmission provider is not uniquely situated to provide Backup Supply Service to its transmission customers, nor does it have a comparative advantage over others in providing such service. Moreover, as Backup Supply Service may require substantial amounts of generation capability, it is inappropriate to require the transmission provider to assume significant generation responsibilities as we functionally unbundle transmission from generation. Although the transmission provider will not be required to offer this service to transmission customers, it may offer voluntarily to provide Backup Supply Service to its transmission customers. Any arrangements for the supply of such service by the transmission provider should be specified in the customer's service agreement. (FERC Order 888, pp 221-223) In a competitive and unregulated generation market, where the local utility does not have the obligation to provide it, but chooses to provide stand-by in an unregulated setting, the providing of this service would simply be a commercial relationship between the local utility and the direct access customer. Presumably it would be economically beneficial to each, relative to their alternatives. Commitment to stand-by obligations under this approach would not require the utility to plan or commit to additional capacity on its system unless it voluntarily contracts to do so. Under the proposition that providing stand-by is an obligation of the local utility, at regulated rates, terms, and conditions, as a regulated ancillary service to a retail direct access customer; stand-by takes on other dimensions. First, from the host utility perspective, such terms give, in effect, a call option on the host utility's power supply by the retail direct access customer. Under an obligatory regulated stand-by approach, the host local utility must plan and build or commit to capacity to serve the retail direct access customer, or reserve existing capacity for that customer, at the expense of its stockholders in terms of foregone earnings from selling that capacity in a competitive market, or at the expense of other customers of the utility in terms of either indirect subsidy or implicitly reduced reliability. From the perspective of a retail direct access customer, obligatory regulated stand-by not only creates a power supply reliability backstop, but it provides a clear economic reference point from which to structure prices, terms, and conditions for the acquisition of power from distant power suppliers. In short, it provides a fixed economic package from which to possibly "game" power supply options. Solution to the Stand-by Issue During the early years of the transition period, customers seeking to utilize direct access retail service may have difficulty in arranging stand-by for off system power supplies. This is because a market for stand-by services may not yet have developed, or because customers or third party providers have not had a opportunity to plan and construct or install such facilities. It is necessary to provide a transitional solution to the stand-by issue. Staff recommends that the local host utility be obliged to offer stand-by to retail direct access customers for an initial period of two years. Customers desiring the service must contract in advance and pay a reservation fee. Stand-by offered by the local host utility during the transitional phase would be offered to retail direct access customers at out-of-pocket cost plus a reasonable adder. This requirement to offer stand-by would be phased out by 2001. Thereafter, the local host utility may, but is not required to offer direct access stand-by. The price, terms and conditions of stand-by would at that point would be competitively based. Stand-by service to direct access customers is different than the existing stand-by service provided by local utilities to "self-service" or parallel operation customers. "Self-service" customers are served by facilities located on the premises of the customers and the host utility has a history of the operation and metered data for the operation which extends over a period of many years. Also, the need for stand-by for self-service is based on individual generator outage characteristics that have a certain degree of randomness and is largely independent from all other generators in the class thus making probabilistic analysis feasible. Direct access customers on the other hand, may change their supplier as opportunities present themselves, both for the customer as well as the supplier. Transmission paths will also change as suppliers change and as load conditions and prices change. However, suppliers outside of Michigan will all utilize the limited available transfer capability into the state. Any change or constraint in available transfer capability (which may be caused by local generator outages, transmission line contingencies, or unexpected load increases in the region) will likely cause a non random coincident demand for the use of stand-by for most customers contracting with external suppliers. Such a situation is most likely to occur during periods of high local and regional loads when local native generation reserves are minimal. Thus, the coincidence of use of stand-by is likely to be much higher for direct access customers than for self-service customers. In conclusion, it is currently impossible to establish a predictable rate class for direct access stand-by service with the certainty to support a regulated cost of service type tariff for the two year transition period. Secondly, due to potential significant differences in coincidence of use, the existing self-service stand-by tariff should not be extended beyond its diversified load parameters. Rate Structure Unbundling The movement to customer choice will require development of new pricing structures that recognize distinctions between competitive and regulated services. During the transition to competition, the pricing of various service offerings should provide appropriate recognition of the cost of services while enabling direct access customers to make informed economic decisions. The current regulated bundled price of electric service will, of necessity, need to be broken into its constituent parts, composed initially of distribution charges, transmission charges, and production charges. Distribution Service Tariffs In order to institute direct access, utilities will need to file tariffs reflecting the charges for regulated distribution services that are to be offered to direct access participants. During the transition period, it is anticipated that the distribution utility will continue to provide services for direct access customers, and those costs should be incorporated into the distribution charges. The distribution service tariff should either reflect or incorporate by reference the appropriate transmission service charges approved by the Federal Energy Regulatory Commission (FERC), transition charges, securitization charges, stand-by charges, and any other appropriate and approved charges. Each utility will also need to prepare appropriate tariff filings to institute specific rules and regulations necessary to commence direct access. While establishment of the distribution charges is a necessary first step in instituting direct access, further unbundling of rates to reflect the production costs embedded in bundled service will provide information valuable to the potential direct access participant. It will be necessary for the utilities to develop systems for the billing of unbundled services. The utilities should investigate and prepare proposals for the provision of further unbundled services for direct access participants and non-participants during the transition period. The rate unbundling process is dependent upon finalization of decisions on a number of other items, including: PSCR freeze, transition cost recovery, level of rate reduction bonds, and FERC decisions on ancillary services. If these issues are not resolved prior to the initial unbundling, there will be a need for successive unbundling. While this could add to customer confusion, further unbundling may be unavoidable as the transition progresses. Nuclear Decommissioning As part of current rates, utilities with nuclear plants collect NRC mandated costs to ensure nuclear site security and safety throughout the life of the plant as well as total costs of decommissioning after the plants are shut-down. The Staff recommends that these obligations be funded through a non-by-passable charge. This charge should continue until adequate funding exists for those activities or until the obligations to perform them are fulfilled. VII. FEDERAL ENERGY REGULATORY COMMISSION ISSUES Commercially Available Transfer Capability The movement within the electric industry to provide direct access to the interconnected bulk power transmission system raises issues that will have to be resolved if successful direct access is to become a practical reality. A primary driver for the move towards direct access is the belief that the creation of a fully competitive generation market will result in lower power supply costs and rates for most customers. The interconnected transmission system is the physical highway that connects generation resources to ultimate load centers and end users. Access to the transmission system must be afforded in a non-discriminatory manner that is fair to all customers and in a way that will not jeopardize the high standard of reliability that has historically been provided to customers. The application of these principals must also recognize the physical limitations of the transmission system both as it currently exists and is likely to develop. On April 24, 1996 the Federal Energy Regulatory Commission (FERC) issued Order No. 888 that required all public utilities that "own, control, or operate facilities used for transmitting energy in interstate commerce to have on file open access non-discriminatory transmission tariffs that contain minimum terms and conditions of non-discriminatory service". The FERC's goal, as stated within that order, was the removal of impediments to competition in the wholesale bulk power marketplace and to bring more, lower cost power to electricity consumers. The move towards retail direct access in Michigan presents similar opportunities for retail customers. The parallel movements however, present new operational challenges for transmission system operators, potential prioritization issues between customers, and possible jurisdictional disputes between federal and state regulatory bodies. The transmission system in Michigan is part of the eastern interconnected network within the United States. Historically, the Michigan system has been used to serve not only retail and wholesale customers within the State, but also to facilitate wholesale transactions between generation resources and customers outside of Michigan as well. While the transmission system has reliably accommodated these supplemental transactions in the past, the move to expand wholesale access federally, and to initiate retail direct access locally, will greatly add to the number of users who desire transmission service. Such access should be afforded so long as it does not jeopardize the reliability benefits realized by all customers. To assure reliable electric service to end users, generator output must match load at all times on a nearly instantaneous basis. This presents a continuous challenge to the system operator because load can vary significantly over various time intervals. In addition to chasing varying load conditions, additional amounts of generation reserve are needed to protect against unforseen losses of generating capacity, unexpected increases in load, and to compensate for thermal losses on the delivery system. Today load requirements within Michigan are primarily supplied by instate generation and supplemented for reliability and cost considerations by out of state resources. The ability to reliably serve current native load levels within the State at certain times of the year is heavily dependent on both the total amount of internal operable generating resources and the total net transfer capability of the transmission interfaces with other non-Michigan utilities. For instance, load within the Consumers Power and Detroit Edison control area (Michigan Electric Coordinated System) of the lower peninsula inclusive of load of local municipal and cooperatives located in the area grew to approximately 18,500 Mw during peak hours in August 1996. Native installed generation within the same area is approximately 19,750. To supplement native generation, no more than 5,000 Mw of transmission net transfer capability is available at any one time within the lower peninsula. This transfer capability is in turn usually reduced during peak periods because transactions involving non Michigan utilities can load up the transmission network. Thus, a limited and varying amount of net transfer capability, at least in relation to total load in Michigan, is available at any one time. At issue is how much of the net transfer capability can be made available for commercial activities without degrading system reliability for all customers. Order No. 888 clearly recognizes that the move towards expanded transmission access should not degrade or impair the reliability of service to native load customers, network customers, and existing transmission customers currently taking firm point to point service. Order No. 888 also requires that all electric utilities subject to the Order, make compliance filings to meet certain new non price pro forma tariff requirements concerning minimum terms and conditions for non-discriminatory transmission service including the requirement that each transmission provider file a methodology to assess available transmission capability (ATC) for expanded commercial use. Consumers Power Company and Detroit Edison filed conforming pro forma tariffs on July 9, 1996. Both filings included a description of the methodology to be used to assess available transmission capability. Each company proposed methodologies that the determination of ATC be done in accordance with a June 1996 report developed by the North American Electric Reliability Council (NERC) entitled "Available Transfer Capability Definitions and Determination". The report, was the product of a national industry effort to establish a framework for determining dynamic ATC of the interconnected transmission network for a commercially viable wholesale electric market. Assessing how ATC determination will affect the development of a retail direct access market within Michigan requires further consideration of aspects of Order No. 888 and how those principles set forth in the Order apply to the load and network transmission system characteristics in the State discussed above. Based on the above factors, interstate ATC into and out of MECS will clearly vary through out the year. FERC Order No. 888 sets forth the requirements and prioritization for two types of transmission service; (1) point to point service, and (2) network service. Based on the initial filings, it appears that no long term firm interstate point to point service (1 year or longer) will be available within MECS for additional wholesale or new retail direct access transactions but that firm point to point for shorter periods and recallable firm point to point service will be available during non-peak periods. In such cases where the transmission provider cannot provide services as requested, Order No. 888 requires the transmission provider to expand or upgrade their transmission system to accommodate the service request contingent upon the transmission customer agreeing to compensate the transmission provider for costs incurred in the expansion. This expansion requirement could prove somewhat problematic for the retail direct access program proposed in this report since many of the physical constraints limiting MECS's interstate transfer capability through the eastern and southern interfaces are located in areas outside this state. Removing the current set of limitations may require a collaborative effort among states adjacent to Michigan, the province of Ontario, and the FERC. For network service, customers will have access to the interface capability but will be limited by their load ratio share of the total interface capability. Given this load ratio limitation, a network would not be able to serve its entire firm load using the interfaces. In addition, for either type of transmission service, it does not appear that a prospective customer will be able to serve their entire local load from an out of state resource on a totally firm basis without backing up the transaction with local generation. For the transaction to be totally firm to the end user, local backup capacity will be required during peak hours of the year when ATC is not available. Independent Transmission System Operator The creation of a truly competitive generation market requires substantive changes to the way that transmission systems have been traditionally operated. Development of a competitive bulk power market requires that barriers to access to transmission be eliminated so that end-use retail and wholesale customers can transmit their market based power purchase to their load location. Currently the vast majority of the transmission network within the United States is owned by public utilities who also own generation resources that will compete in the new market structure. One restructuring concern is the use or control of the transmission system by transmission owners or operators of the network in a manner that creates disadvantages for other generation owning entities. To help alleviate this market concern, the electric industry has been exploring the creation of independent transmission system operators (ISO's) who will provide non-discriminatory access to the network when transfer capability is available and at the same time ensure that reliability of the network system is not threatened by the increased demands placed on it by the emergence of a competitive generation market. Because an ISO will likely to be viewed as facilitating transmission related interstate commerce, jurisdiction for the ISO will likely reside with the Federal Energy Regulatory Commission (FERC). In Order No. 888, the FERC did not require formation of an ISO at this time but did encourage the formation of properly structured ISO's within the industry. To help facilitate the formation of ISO's, the FERC set forth eleven basic principles that must be met when the FERC evaluates ISO requests encompassing entire control areas such as may be applicable to major portions of this State. The principles are as follows: 1. The ISO's governance should be structured in a fair and non-discriminatory manner. 2. An ISO and its employees should have no financial interest in the economic performance of any power market participant. An ISO should adopt and enforce strict conflict of interest standards. 3. An ISO should provide open access to the transmission system and all services under its control at non-pancaked rates pursuant to a single, unbundled, grid-wide tariff that applies to all eligible users in a non-discriminatory manner. 4. An ISO should have the primary responsibility in ensuring short-term reliability of grid operations. Its role in this responsibility should be well-defined and comply with applicable standards set by NERC and the regional reliability council. 5. An ISO should have control over the operation of interconnected transmission facilities within its region. 6. An ISO should identify constraints on the system and be able to take operational actions to relieve those constraints within the trading rules established by the governing body. These rules should promote efficient trading. 7. The ISO should have appropriate incentives for efficient management and administration and should procure the services needed for such management and administration in an open competitive market. 8. An ISO's transmission and ancillary services pricing policies should promote the efficient use of and investment in generation, transmission, and consumption. An ISO or a Regional Transmission Group (RTG) of which the ISO is a member should conduct such studies as may be necessary to identify operational problems or appropriate expansions. 9. An ISO should make transmission system information publicly available on a timely basis via an electronic information network consistent with the FERC's requirements. 10. An ISO should develop mechanisms to coordinate with neighboring control areas. 11. An ISO should establish an ADR process to resolve disputes in the first instance. Staff supports the creation of an ISO in Michigan for the control area that is currently encompassed by the Michigan Electric Coordinated System (MECS) in the lower peninsula and is willing to work with all major stakeholders in the development of such an entity. The creation of a Michigan based ISO will aid the development of a competitive retail and wholesale generation market within the state, and also help to assure that the reliability of electric service currently provided to Michigan residents is not threatened by increased demands placed on the system. The creation of such an ISO is essential to ensure that non-discriminatory direct access is provided and reliability concerns specific to the Michigan are addressed in the provision of direct access. However, it is unlikely that such an ISO could be operational until mid to late 1998 at the earliest. Operation of the Michigan ISO contemporaneous with the initiation of the retail direct access program recommended in this report is not absolutely essential given the phase-in of the program recommended. The Michigan ISO could be eventually participate or involve into a more regional ISO if such a movement is determined to provide substantive benefit to customers within the State. Michigan Power Exchange A power exchange is a spot market for electricity wherein customers can purchase power (normally on an hour ahead or day ahead basis) to meet their electricity needs in part or in total. Participation in a power exchange is voluntary on the part of both generators and electricity consumers. Many believe that a power exchange is desirable in a competitive generation market and will naturally emerge as the market evolves. Most power exchanges work in a manner wherein an hourly market clearing price is established, by matching electricity consumers bids to purchase electricity with bids of suppliers to sell electricity. For each hour the market clearing price (which is visible to all participants and non-participants) is paid to all suppliers providing electricity to the power exchange and by all customers purchasing electricity from the power exchange. The native load customers of Consumers Power and Detroit Edison are presently served by the MECS which ensures reliable operation of the power supply system jointly operated by both companies through the use of economic dispatch of the native load generation and purchases of both companies to minimize the energy costs to their customers. MECS operation after 1996 must be revised to conform with the requirements of FERC Order No. 888 regarding open membership and operation under a joint transmission tariff available to all eligible entities. Pending the outcome of MECS restructuring in the future, the Staff will work with utilities and other stakeholders to develop a Michigan-based exchange or regional power exchange that provides the customers wishing to purchase their power directly from other generation sources. There is not an immediate need for the formation of a power exchange given the phased nature of the program proposed within this report. Because a power exchange engages in sales for resale, it will likely be regulated by the FERC. Transmission Access Tariffs and Ancillary Services A major aspect of the current restructuring movement is a need to functionally unbundle the generation, transmission, and distribution functions to provide the customer an opportunity to choose different providers for certain of these functions in a competitive market framework. Unbundling in the electric industry is a relatively new concept. In addition to the fact that rates for service have historically been developed on a bundled basis, the physical electric system that produces the end product has evolved as a network of generation, transmission, and distribution facilities that operate on a coordinated basis to deliver a reliable end product to all consumers. To properly accomplish unbundling, all the individual services provided by the basic elements of the network system must be identified, and the costs associated with each service assigned to the function providing that service so that cost compensatory unbundled rates for those services can be developed. Customers who desire direct use of, or access to, transmission system network to transport energy and capacity purchases from competitive market based generation will need to acquire, or self- provide certain ancillary services, in addition to the capacity on the transmission system, if delivery of their purchase is to be accomplished in a reliable manner. These services are necessary to effect the transaction (scheduling, system control, and dispatch service), maintain voltage on the transmission system within an acceptable range (reactive supply and voltage control from generation sources service), maintain integrity of the system while the transaction is occurring (regulation and frequency response), and provide for differences between the scheduled and actual delivery of energy to a level over a single hour (energy imbalance). Historically, jurisdiction for development of rates to recover costs related to transmission has been split between local state commissions for direct retail service, and the Federal Energy Regulatory Commission (FERC) for wholesale transactions. The current industry movement towards a competitive generation direct access market is also being accomplished within both the state and federal jurisdictions. In recent years, a number of jurisdictional issues have developed that relate to the movement towards direct access. In April of 1994, the Michigan Public Service Commission (Commission) issued an order in Cases U-10143 and U-10176 that approved an experimental retail direct access program. In June 1995, the Commission issued a second order in those cases that set forth the rates and requirements for the experimental program including rates and requirements associated with ancillary services. In November 1996, the Commission issued an order in Cases U-10685, U-10754, and U-10787 that established a Direct Access (DA) tariff for Consumers Power Company for additional direct retail access. The DA tariff also included rates and requirements for ancillary services. At the Federal level, the FERC issued Order No. 888 on April 24, 1996 in which it required all public utilities who own, control, or operate facilities used for transmitting electric power in interstate commerce to have on file an open access transmission tariff that contained the minimum terms and conditions for non-discriminatory service. Order No. 888 set forth terms and conditions for six ancillary services. The order also clarified FERC's view as to the extent of their jurisdiction relating to unbundled retail transmission service used in interstate commerce by public utilities. The FERC had expressed in previous Notice of Proposed Rulemakings that it had "exclusive jurisdiction over unbundled retail transmission in interstate commerce by public utilities" and that it has "exclusive jurisdiction over the rates, terms, and conditions of unbundled retail transmission in interstate commerce by public utilities, up to the point of local distribution". In Order 888, the FERC commented that the legislative history of the Federal Power Act and case law interpreting federal/state jurisdiction under the Act grew out of a market structure in which electricity and transmission were bought and sold on a bundled basis and that such interpretations do not resolve jurisdictional issues when they arise in the context of emerging market structures and unbundled transactions. The FERC subsequently found that they were correct in asserting jurisdiction over the transmission component of an unbundled retail wheeling transaction but would give "deference" to state determinations as to what constitutes transmission and local distribution so long as the state jurisdiction applied seven functional tests for defining local distribution that the FERC included within the Order No. 888. Staff believes the FERC reserved rate jurisdiction for the transmission component of a retail direct access program by these findings, a belief supported in part by discussion in the Order that retail and wholesale unbundling raise numerous difficult jurisdictional issues that would be more appropriately considered when the FERC "reviews unbundled retail transmission tariffs that may come before us in the context of a state retail wheeling program". As discussed above, transmission service and ancillary service tariffs for unbundled retail and wholesale service have been and are being developed at both the state and federal levels. For instance while Order No. 888 defined what ancillary services should be offered and the terms of those services, it deferred resolution of price issues to latter cases involving pro forma tariff filings that are currently before the FERC. The FERC also deferred individual utility resolution of the transmission and distribution split for wholesale purposes to the pro forma cases. Similarly, the Michigan Commission has already approved retail direct access and ancillary service tariffs for the experimental retail wheeling programs and in Consumers Power's Rate DA approval. Aside from the jurisdictional question posed above, the contents of the tariffs, while similar in many respects, do have significant differences. To facilitate the movement to direct access, Staff believes it may prove useful to work within the FERC pro forma cases so definitions that are workable for both retail and wholesale direct access programs can be developed. Similarly, these cases will provide an opportunity to mirror tariffs at the retail and wholesale level for basic transmission service and ancillary services so long as the type of services required, equipment used, and costs associated with such tariff development are similar. Although the FERC has reserved rate setting jurisdiction for the transmission component of an unbundled retail direct access program, they have strongly endorsed a "comparability " concept. By mirroring the tariffs, the Michigan participants may gain acceptance of their retail direct access tariffs and avoid a jurisdiction dispute with the FERC. As a starting point, the open access transmission tariffs for Consumers Power and Detroit Edison before the FERC require a separation of transmission and distribution plant when direct access occurs using the seven functional tests that were set forth in Order No. 888. The Staff has been involved in discussions with Consumers Power, Detroit Edison, and the FERC Policy Staff regarding the proposed split between FERC jurisdictional transmission facilities and Commission jurisdictional distribution facilities using the seven functional tests as a basis. The Staff is in basic agreement with the methodologies proposed by the two Michigan companies. The methodologies define transmission as the network system used to interconnect the two utilities with neighboring transmission systems and to transmit bulk power from interconnections and power plants to major load centers for further distribution. Detroit Edison and Consumers Power define transmission as facilities operating at a voltage of 120 kv and above excluding radial lines that serve retail end-use customers directly. These 120 kv radial lines to end use customers are considered direct assignment facilities. Distribution is defined as the system used to transmit power from the transmission system to distribution facilities which ultimately connect directly to industrial, commercial, residential and other retail customers and the facilities for certain wholesale for resale customers. This definition would include 120 kv and 138 kv radials to end-use customers. In the case of Detroit Edison, the company identified and removed from its network transmission rate, approximately 50 radial lines that currently serve retail customers. The two pro forma cases also address the rates and conditions for ancillary services as required by Order No. 888. Staff believes that the initial formal determination by the FERC in these two cases will establish the standard of comparability for Consumers Power and Detroit Edison transmission access and ancillary services tariffs used for retail direct access. Given that the FERC is likely to use the final determinations in the pro forma cases as a threshold for comparability, Staff would suggest that all Michigan parties coordinate their positions in these cases to the greatest extent possible so that retail access considerations do not inadvertently get overlooked in the establishment of wholesale tariffs that may be ultimately used as a benchmark for retail direct access tariffs. Mirroring ancillary service tariffs for comparability considerations would in all likelihood require action in both jurisdictions. Staff notes that the two retail direct access ancillary service tariffs approved by the Commission to date contain enough differences between themselves and the two wholesale filings that they may not be considered totally comparable. Resolution of the specific differences in the tariffs may thus require formal action in both jurisdictions. MPSC Regulatory Approvals Required The power seller in a retail direct access transaction must obtain a certificate of public convenience and necessity from the MPSC pursuant to Act 69, and must obtain MPSC approval of the power sales agreement with the retail direct access customer. All pricing terms of such power sales agreements must be publicly disclosed during the transition period. VII. CUSTOMER IMPACT Customers are favorably impacted by the program outlined in this Report in two ways. First, as previously noted, all customer classes directly benefit from the use of rate reduction bonds. The overall rate reduction to Michigan citizens is expected to exceed $300 million. Second, customers benefit from the ability to "shop around" for the least expensive power supplier. The value of this depends upon the difference between the amount that the customer would pay under a traditional bundled rate and the sum of the charges (generation, transmission, distribution, and transition) that would be paid by a direct access customer. This differential is somewhat difficult to estimate precisely because the generation cost will be determined by the market and transmission and distribution rates have not yet been unbundled. However, the charts below depict the average sales rate being paid by various size customers today with the sum of charges other than generation that would be paid by a direct access customer. Consumers Power Company Customer Size Sales Rate Direct Access Difference 2.5 MW 5.3 ›/kwh 2.0 ›/kwh 3.3 ›/kwh 5.0 MW 5.3 ›/kwh 1.9 ›/kwh 3.4 ›/kwh 10.0 MW 5.3 ›/kwh 1.8 ›/kwh 3.5 ›/kwh Detroit Edison Company Customer Size Sales Rate Direct Access Difference 2.5 MW 5.8 ›/kwh 1.9 ›/kwh 3.9 ›/kwh 5.0 MW 5.8 ›/kwh 1.8 ›/kwh 4.0 ›/kwh 10.0 MW 5.8 ›/kwh 1.8 ›/kwh 4.0 ›/kwh These charts indicate that a direct access customer could reduce electricity costs if power generation and ancillary services are available for less than about 3« ›/kwh on Consumers' system and less than approximately 4 ›/kwh on Detroit Edison. Pilot programs conducted to date have produced power supply costs in the range of 2 to 3 ›/kwh. Accordingly, it appears that direct access should be an attractive means of reducing electricity costs. Another way to compare the potential impact is by analyzing the electric rates prior to the program with estimated rates after. This is important because it was concerns with high electric rates in Michigan that led to the current interest in restructuring. The first chart below shows the average electric rate in Michigan for each customer class along with the corresponding regional and national average. The second chart shows the differential between Michigan rates and the regional and national averages. Average Electric Rates in ›/kwh Michigan Region Total U. S. Residential 8.83 8.72 8.80 Commercial 8.26 7.59 7.86 Industrial 5.19 4.79 4.92 Michigan Electric Rate Differentials Michigan Price Compared With: Region Total U. S. Residential 1.3% Above 0.3% Above Commercial 8.8% Above 5.1% Above Industrial 8.4% Above 5.5% Above As this chart shows, Michigan residential rates are nearly competitive with other states, but that commercial and industrial rates are somewhat higher. The combined effects of rate reductions resulting from securitization of certain assets (about 9% for Detroit Edison alone), and from implementation of the large scale phase-in program (about 10% of customer load during the first four years) for direct access suggests that the rate levels for all three major sectors of the electricity market: residential, commercial and industrial, for Michigan consumers will be very attractive when compared to the Region or the U.S. as a whole. The exact nature of the rate changes depends on the cost structures as well as the competitive situation. In short, the results of the proposal outlined in this document will be that Michigan residential, commercial and industrial customers will have lower rates and customer choice. The combination of rate reduction bonds and direct access have the potential to make Michigan electric rates competitive in a short period of time. Rates will probably be below the regional and national averages for all classes. Of course, this assumes that rates in other states remain stable. Since many other states are also pursuing direct access (e.g., Massachusetts, New Hampshire, Rhode Island, Pennsylvania, California, New York), national rates may also decline. Although this would reduce Michigan's apparent advantage, it would be even more important that Michigan act aggressively to avoid eroding our competitive position. VIII. SOCIAL ISSUES Environmental Concerns Although economic considerations have provided the main focus in the electric restructuring debate, the electric industry impacts numerous social policy issues. One of the primary social issues involves the relationship between electric power and the environment. For example, a report by the Michigan Relative Risk Analysis Project identified numerous environmental risk categories associated with electric power: global climate change, energy production and consumption, atmospheric transport and deposition of air toxins, generation and disposal of high- and low-level radioactive waste, photochemical smog, acid deposition, and electromagnetic field effects. The Staff believes that the electric restructuring program outlined in this report could have a favorable impact on the environment for three reasons. First, pilot programs conducted in other states have shown that, given a choice, many customers will support environmentally clean power production. However, under the current system, customers have no ability make such choices and the market for renewable power has not developed significantly. The direct access program will allow customers to choose from available "Green" power suppliers, thus enhancing the market for clean generation. Second, a direct access program should promote the development of smaller gas-fired power plants. In the past, power production has come predominantly from large-scale nuclear and coal facilities, each of which raises environmental concerns. A more dispersed competitive power market, based on gas-fired generation, will be more environmentally friendly, since gas combustion produces virtually no sulfur oxides which contribute to acid rain and also produces less carbon dioxide than burning coal. Third, a program of customer choice will encourage the development of new competitive energy conservation programs. In the past, the primary delivery mechanism for energy conservation has been through utility programs authorized by the Public Service Commission. Unfortunately, evaluations of these programs have demonstrated that they are not cost effective. Direct access will allow energy service companies to develop innovative programs tailored to meet the individual needs of their customers. For example, energy service companies may become partners with power suppliers to offer customers a "package" of energy supply and conservation measures that would be more attractive to the customer than either option separately. These approaches will simultaneously benefit the customer and the environment. Universal Service The second main social issue involving electric power is the question of universal service. Electricity is more than just a commodity -- it is a fundamental component of modern daily living. In the past, a variety of programs have been developed to assure that all customers have reasonable access to electric power (e.g. senior citizen rates, winter shut-off protection, etc.) The customer choice program outlined herein does not remove any of these support programs. Indeed, the potential rate reductions incorporated in the plan should make electric power more accessible to all citizens. In any event, the program is designed to be compatible with any future social "safety-net" that policy-makers should choose to implement. IX. LEGISLATION In order to place into effect many of the elements of the electric utility restructuring proposal discussed in this document, legislative concurrence and authorization should be sought for a number of elements. Those elements are as follows: First, it is clear that legislation is necessary to permit the creation of a Trust for the securitization of rate reduction bonds, which would reduce rates and debt and equity from the balance sheet of a utility electing that option. Second, legislative authorization for the collection of transition charges, and perhaps other surcharges, may be desirable to confirm the certainty of future collection of the charges, before a full implementation of retail direct access can move forward. Third, it appears that legislation may be desirable to implement modifications to or elimination of the PSCR to accommodate the freeze on generation cost pass-throughs envisioned in the proposal. In addition, it may be desirable to codify in legislation, authority to implement performance-based regulation, deregulate generation, and unbundle rates. Also, Act 69, which requires that any "public utility" proposing to provide electric service in the franchised service area of another receive a Certificate of Convenience and Necessity from the Commission as a condition precedent to providing service may need modification. Finally, consideration should be given to allowing all suppliers to contract with the customer for power supply without Commission approval.