UNBUNDLED SERVICES AND STANDARD OFFER WORKING GROUP
REPORT TO THE COMMISSION
TABLE OF CONTENTS

Executive Summary

I. Introduction

II. Standard Offer Service

III. Unbundled Services

IV. System Benefits Charge

V. Measurement/Cost Issues

VI. Solar Portfolio Standard

VII. Metering and Meter Reading Issues

VIII. Billing & Collections

IX. Customer Requirements

X. Administrative Requirements

XI. Recommendations

Appendices:

Appendix D -- Competition in Metering and Meter Reading Services

EXECUTIVE SUMMARY

This Section of the report summarizes the findings and recommendations of the Working Group assembled pursuant to R14-2-1601.I. to explore the issues inherent in the offering of "unbundled" electric services and in the offering of traditional "standard offer" service.  Additionally, R14-2-1608 added the issues surrounding System Benefits Charges and Staff added the Solar Portfolio Standard established in R14-2-1609 to this Working Group's considerations.

Issues identified by the Working Group for consideration were grouped into the following categories: Standard Offer Service; Unbundled Services; System Benefits Charge; Measurement and Cost; Solar Portfolio Standard; Metering and Meter Reading; Billing and Collection; Customer Requirements; and Administrative Requirements. Three subcommittees (Solar Portfolio Standard, Metering, and Billing and Collection) were formed to analyze certain specific issues and submitted reports to the full Working Group. The full Working Group evaluated all other issues.

Three types of conclusions were reached by the Working Group: 1) Consensus items, where the Group agreed on the meaning of the existing rules relative to a given subject; 2) Recommendations, in which the Group agreed that a change to the rules was needed in a given area; 3) Recommendations for further work. Additionally, Staff itself made some recommendations.

The highlights of each of the four categories are contained in this report summary.

1. THE WORKING GROUP CAME TO CONSENSUS ON THESE ISSUES:

Standard Offer Service

• Can New Entrants Provide Standard Offer Service? Under the existing Rules, only incumbent utilities could offer a Standard Offer Service as defined in R14-2-1606.A. However, new providers could offer a package of unbundled services that is similar to Standard Offer Service.
• May a New Provider Offer Service to Those Customers not in the Competitive Market During the Transition Period? New providers could not offer service to non-participants under the current Rules. This does not apply to buy-through transactions as authorized in R14-2-1604.G.

Unbundled Services

• What Unbundled Services May Be Offered? While not specifically articulated in the Rules, there seems to be no prohibition to incumbent utilities and new providers alike "rebundling" various unbundled service elements and offering those in the competitive market, subject to approval of tariffs by the Arizona Corporation Commission.
• What is the Extent of State Jurisdiction in Transmission Services? Unbundled transmission is effectively under FERC jurisdiction, however, if it is found that an Affected Utility's current FERC open access tariff requires modification to fully accommodate retail access, then the Arizona Commission may have to cooperate or concur with the incumbent utilities for an unbundled retail transmission tariff to the FERC. Additionally, the Arizona Commission would have to be involved in the "jurisdictional bright-line" that is proposed to the FERC for the jurisdictional separation of distribution and transmission facilities.
• Are Existing Line Extension Policies Still Valid? The traditional theory remains unchanged, that cost-causers will pay the costs of line extensions, perhaps with a certain free allowance.
• What Types of Ancillary Services May Be Offered? The unbundled ancillary services that could be offered would depend, at least in part, on the provisions of FERC Order 888. One aspect of the system that the Group agreed was not an ancillary service was operation and maintenance of the distribution system.
• Should Load Management/Energy Management Services Be Regulated? This type of service should be unregulated and left to the competitive market.
• Should the Sum of the Prices of Unbundled Network Elements Always Equal the Price of Traditional, Bundled, Standard Offer Service? Since unbundled elements can be bought from various sources, the consensus answer to this question was no.

System Benefits Charge

• DSM Portion of the System Benefits Charge. The Working Group agreed that DSM measures that are already market driven should not be included in programs that are funded by the System Benefits Charge. The Working Group agreed that the DSM portion of the System Benefits Charge should include those programs that are designed to reduce or overcome market barriers to market driven energy efficiency that are not otherwise addressed adequately in competitive or regulated markets.
• Nuclear Decommissioning Portion of the System Benefits Charge. The Working Group agreed that nuclear decommissioning charges should be entered as a separate line item of the System Benefits Charge. Whether the costs of nuclear disposal should be included was not resolved.

• Meter Ownership. Meter ownership and control of the metering equipment would be limited to the Electric Service Provider or the Local Distribution Company at the customer's choice.
• Who Installs the Meters? Responsibility for the installation of meters rests with either the Electric Service Provider or the Local Distribution Company.
• What Part, if any, of the LDC's Metering Infrastructure (i.e., PTs and CTs, Meter Socket, etc.) Will Be Made Available to Facilitate Third Party Installation of an Hourly Meter? The metering infrastructure (PT, CT, socket) would be transferred to the Electric Service Provider with appropriate compensation to the Local Distribution Company.
• If Metering is a Competitive Service, What Becomes of the Meter and Communication System Installed by an ESP When its Contract Expires with the Customer? Is it Removed? How Does the LDC Get its Metered Data then? Any transaction between two parties is a commercial (market) transaction. A timely procedure must be in place to ensure an orderly transition.
• Should There Be a Provider of Last Resort for Metering and Meter Reading Services? There should be a provider of last resort for metering services. The energy provider of last resort should be the metering provider of last resort.
• Metering Data Exchange. A statewide standard data file format must be implemented. A workshop should be held to help develop a statewide standard data file format.
• What Are the Minimum Metering Requirements to Accommodate Direct Access? Minimum metering requirements for direct access customers over 20 kW (or an annual equivalent kWh for 20 kW demand) should consist of hourly consumption measurement meters.
• Should Load Profiling Be Allowed? There was consensus that load profiling should be allowed as an economic alternative to hourly metering. However, certain details remain to be resolved.
• Meter Data Access Rights. Access to end-use data should be available to the LDC, the ESP, and their designated metering and billing agents who require the data for operations and billing. No other party may have access to such data without specific authorization from the end-use customer.
• Metering Certification Process. In the CC&N process, the qualifications and certification programs for the personnel of companies applying for a CC&N will be evaluated.

• What Billing Options Are Available? The Working Group identified three billing options: two separate bills, a combined bill from the LDC, or a combined bill from the ESP.
• Who Is the Responsible Paying Party? The responsible paying party is the end user or customer of record.
• Who Should Have the Authority to Order a Disconnect, Connect or Reconnect? Functionally, disconnects and connects should be handled by the LDC. Only the LDC should order connects, disconnects and reconnects.
• What Minimum Information Needs to Be Included on the Bill? The consensus of the Working Group was that certain minimum information needs to be included on residential customers' bills for customers who take other than standard offer service. However, the billing agent may customize a residential bill and include less information upon receiving a written request by a residential customer stating what information should appear on his/her bill.
• What Consumer Protection Standards Need to Be in Place, Including Confidentiality of Billing Data, etc.? Customer specific billing data will only be released to parties with whom the customer has given authorization for the disclosed purpose.

• The revised objectives of the Solar Portfolio Standard should be included in the Rules.
• The Solar Portfolio Standard penalty should be changed to a mechanism whereby the penalty funds are utilized to install solar electricity systems in Arizona.
• The Solar Portfolio Standard should include incentives of some type to encourage the electric service providers to take actions which will better meet the objectives of the solar portfolio standard.
• Electric Service Providers should be allowed to "bank" solar kWh for use in later years.
• Excess solar kWh should be tradable commodities that may be sold to other interested parties.

• A definition of metering and meter reading services should be added to the Rules.

Billing and Collection

• The existing rules should be amended such that, assuming the data communications interface between the LDC and ESP have been established and the metering requirements are met, a customer or its authorized agent must provide 15 days advance notification to the LDC and existing ESP of his/her intent to switch suppliers.

Customer Requirements

• The existing rules should be amended to require that any tariffs submitted for competitive unbundled services include information about any additional elements necessary for the consumer to receive full electric service.
• The existing rules should be augmented for customers in the competitive environment, to indicate that the telephone numbers of the Electric Service Provider, the Local Distribution Company, and the Arizona Corporation Commission should be included on the bill.

• Staff recommends that the issue of provider of last resort be addressed by the Commission at the same time as the Commission makes a determination whether competition has been substantially implemented, pursuant to R14-2-1606.

System Benefits Charge

• Staff recommends that, if the Commission decides to allow an independent SBC administrator, that the Commission relieve the affected utilities from the existing, related Commission requirements to perform such programs and provide such services.
• Staff recommends that if the Commission decides to move to an independent SBC administration, that it be done over a reasonable transition period, to allow the affected utilities to efficiently transfer existing programs to the new, independent administrator.
• Staff recommends that, if the Commission opts for an independent SBC Administrator, the party making the triennial filing should change from the affected utility to the administrator, for certain of the programs mentioned.

• RECOMMENDATIONS CONCERNING FURTHER WORK

• The Working Group recommends that the Metering Subcommittee be allowed to continue meeting until the following issues are resolved:

1. The Load Profiling methodology details are developed.
2. Minimum metering requirements are drafted.
3. The universal metering identifier that should be used is determined.
4. Proposed Performance Metering Specifications and Standards are finalized.
5. A set of validating, editing, and estimating (VEE) standards are developed.
6. The details of open architecture for metering are finalized

I. INTRODUCTION

The purpose of this report is to present the findings and recommendations of a special Working Group assembled to explore the issues inherent in the offering of "unbundled" electric services and in the offering of traditional "Standard Offer" Service.

On December 26, 1996, the Arizona Corporation Commission issued Decision No. 59943, which established rules (Rules) designed to provide for a phased transition to a competitive retail power market. These rules provided inter alia, for incumbent electric utilities to make at least 20% of their 1995 system retail peak demand available for competitive generation supply to all customer classes on January 1, 1999. The required eligibility will increase to 50% on January 1, 2001. Full competitive generation is scheduled to occur no later than January 1, 2003.

During this transition to a more competitive environment, incumbent utilities will still be required to offer traditional, Standard Offer Service to those customers that are not part of the competitive market, in addition to offering unbundled service to those customers that are part of the competitive market. The issues that arise for both incumbent utilities as well as new entrant electric service providers are discussed below.

Rule R14-2-1606.I. required the creation of a Working Group comprised of all stakeholders in the electric restructuring process to evaluate certain key items, including:

Rule R14-2-1608 added the issues surrounding System Benefits Charges to the task of this Working Group. (System Benefits Charges are explained elsewhere in this report.)

Finally, Staff determined that the Solar Portfolio Standard established in R14-2-1609 should also make up a part of this Working Group's considerations.

By the Rules, the Working Group was charged with making its recommendations to the Commission by November 1, 1997.

The first meeting of the Working Group took place on April 9, 1997. A list of those Working Group participants and their representatives are appended to this report.

At the first meeting, a list of questions to be addressed was developed by the Working Group. Those questions were categorized into the following groupings, each of which is the subject of a section of this report:

Procedurally, the Group addressed each issue individually, over the subsequent five months. At the outset, the only Subcommittee established to address a particular area of concern was for the Solar Portfolio Standard. Subsequently, Subcommittees were established to address metering issues, and to address billing and collection issues. The full Working Group discussed all other issues.

Each of the Subcommittees submitted a report to the full Working Group containing their analyses, that constitute the basis for the Sections of this report on Solar Portfolio Standard, Metering and Meter Reading, and Billing and Collection.

No formal voting mechanism was established for the Working Group as a whole. When questions/issues were addressed, consensus was sought. In those instances where consensus was reached, it does not necessarily mean that there was unanimity among the members of the Working Group present at that particular meeting, but simply that the vast majority of those present were in agreement with the conclusion.

Throughout the remainder of this report are found the various issues analyzed by the Working Group, along with any recommendations. When analyzing each issue, the paramount question that the Group tried to answer was "Does a particular rule need to be modified?" While consensus was reached on some issues, there remains substantial disagreement on others. In those cases where no consensus was reached, the various positions and the differences between them have been crystallized to the extent possible.

Additionally, appended to this report are the unedited comments of the parties with respect to any issue a given party cared to address. These comments are intended to speak for themselves, and serve to further point out the overall complexity of the issues involved in transition to retail competition, and the importance of these issues and their resolution to the various stakeholders. As in most of the other states considering retail competition, the Commission will likely have to decide among competing interests on many key issues. Due to time constraints, the Working Group and Subcommittees focused on larger issues first, moving to operational details as time permitted. Additional details will require resolution prior to the beginning of the partial competitive market on January 1, 1999.

II. STANDARD OFFER SERVICE

Standard Offer Service is the traditional "bundled" service offering that electric utilities have historically provided customers in designated monopoly areas at regulated rates. Pursuant to the Rules, existing incumbent utilities may file new tariffs to offer Standard Offer Service. If they chose to do so, they must file such tariffs by December 31, 1997. According to the Rule, if the incumbent utility chooses to not file new Standard Offer tariffs then the tariffs in effect on that date will constitute the Standard Offer Service. The rules further state that the rates for this service must reflect costs. Finally, the Rules state that if an incumbent utility chooses to file a new Standard Offer tariff, that it is not expected that the rate for the service would increase (R14-1606.B.2).

Pursuant to the Rules, Standard Offer Service is required to be offered by incumbent utilities until the Commission has decided that competition has been substantially implemented for a particular class of customers and all stranded costs for that affected class of customers has been recovered. This determination may be made by application of an incumbent utility, or upon the Commission's own motion.

A. AREAS OF AGREEMENT

1. ISSUE: Definition of Standard Offer Service. The first question the Working Group evaluated was whether the definition of Standard Offer Service was adequate. The consensus of the Group is that the definition is adequate, and that the mechanism is fairly clear insofar as incumbent utilities are concerned. Incumbent utilities understand that they will be required to offer this service at cost-based rates, set pursuant to traditional ratemaking principles, to consumers during the transition period. When competitive conditions exist, pursuant to R14-2-1606.A, the market will determine whether a provider offers what has traditionally been known as Standard Offer Service.

2. ISSUE: Can New Entrants Provide Standard Offer Service? One question raised by potential new providers into the market is whether they, in seeking to maximize their market share of the load open to retail competition (20% in 1999, and 50% in 2001), would be eligible to offer Standard Offer Service. The Working Group concluded that under the existing Rules, that only incumbent utilities could offer a Standard Offer Service as defined in R14-2-1606.A. However, new providers could offer bundled services pursuant to R14-2-1606, by obtaining and bundling together the various service elements (e.g. generation, transmission, distribution, metering and meter reading, billing and collection) and offering the service to any eligible competitive customers that wanted to change from their traditional supplier, but wanted "one stop shopping" for electric service. In other words, new entrants could offer a package of services that is similar to Standard Offer Service except the name that is used to describe it under the Rule. Pursuant to R14-2-1606, new entrants would have to file tariffs to offer any service and documentation for its proposed rates.

3. ISSUE: May a New Provider Offer Service to Those Customers not in the Competitive Market During the Transition Period? Another question discussed by the Group was whether a new energy provider could offer Standard Offer Service (or a package of service elements that resembles Standard Offer Service) to the 80% (or 50%) of the load not offered retail competition during the transition. While the Group, as mentioned above, felt that the existing Rules allowed for new providers to offer what is essentially Standard Offer Service to those consumers in the competitive market, permitting new providers to offer such a service to those (80% or 50%) not yet in the competitive market would essentially amount to an immediate "flash-cut" (i.e., moving to 100% competition all at once) to competition. This is a scenario not currently contemplated by the Rules. Accordingly, there was a consensus that new providers could not offer this service to non-participants under the current Rules. This does not apply to buy-through transactions, as authorized in R14-2-1604.G. {Discussion of this issue led to a discussion of whether a "flash-cut" to competition was desirable. While there was some sentiment in favor of such a position, there was also agreement that January 1, 1999, would be an unreasonable date for such an action. Others believe a flash cut has merit, however, they are opposed to any delay in the implementation date, and therefore, prefer a phase-in starting January 1, 1999, over a flash cut at a later date. Moreover, it is more within the purview of the Customer Selection Working Group to evaluate this issue and present any recommendations for changes in Rules to the Commission.}

B. UNRESOLVED AREA

ISSUE: Provider of Last Resort in a Competitive Market. Finally, there was some discussion of who should serve those eligible to choose an alternative provider, but not choosing one. Pursuant to the current rule, the incumbent utilities have the obligation to serve and are the energy providers of last resort during the transition period to a fully competitive market. Potential new providers felt that they should have the opportunity to provide service to those "non-choosers" either on a random assignment basis, or perhaps through a bidding process to be a "default provider" of sorts. The answer to this question depends, though, on how the Customer Selection Working Group recommends, and how the Commission decides on the methods of selecting participants in the competitive market during the transition. If the selection method is one in which potential participants are contacted until the requisite number make a choice of supplier, the issue becomes moot. If, on the other hand, 20% (in 1999) of the universe of customers are selected as being eligible for alternative suppliers, and a certain portion of that 20% does not choose another supplier, potential new providers felt that they should have the opportunity to provide service to those "non-choosers" either on a random assignment basis, or perhaps through a bidding process to be a "default provider" of sorts. Incumbent utilities, on the other hand, argue that customers that do not choose to exercise their option to enter the competitive market have made a choice, that is, to stay with the incumbent utility. Further, there was discussion that customer dissatisfaction and complaints could result if customers were involuntarily removed from their existing provider.

However, the discussion on this issue, while not relevant to this Working Group for the moment, did serve to raise the question of who would be a provider of last resort in a competitive market, and how that entity or entities would be selected/designated. That is, if a market were considered to be competitive such that Standard Offer Service need no longer be offered by incumbent utilities, would the incumbent utility be obligated to serve those in their historic service territory, or could it "pick and choose"? If no obligation to serve existed, how would those who would otherwise be left unserved be handled? Presumably in a competitive environment the only customers left unserved would be those that are bad credit risks. Would some form of public/general ratepayer assistance be required to allow a competitive provider to profitably serve? It would be at that time that the problem would come to the fore since Standard Offer Service would no longer be required to be offered. To ensure that this obligation is not forgotten with the passage of time, Staff would recommend that the Rules be modified.

III. UNBUNDLED SERVICES

The Rules provide that no later than December 31, 1997, each incumbent utility must file tariffs offering unbundled services. The services that are required to be "unbundled" and offered separately pursuant to tariff include:

With electric competition, incumbent utilities will essentially transform their transmission and distribution services into common carrier type services. This means that any eligible supplier (or consumer) will have access to transmission, distribution, and ancillary services at comparable, nondiscriminatory rates. The Commission would set rates for unbundled distribution and other services (where it has jurisdiction). The Rules provide that these rates be cost-based and may be downwardly flexible. Cost support information would have to be provided along with the proposed tariffs for Commission analysis.

1. ISSUE: What Unbundled Services May Be Offered? While the Rules specify the list of services that are required to be unbundled, much of the discussion of the Working Group centered on the additional services that could be offered. The group did agree that while not specifically articulated in the Rules, there seemed to be no prohibition to incumbent utilities and new providers alike "rebundling" various unbundled service elements and offering those in the competitive market. Of course, tariffs would have to be filed for these services and Commission approval granted. These services would be optional. No change to the Rules would be necessary to accomplish this.

2. UNRESOLVED AREA

ISSUE: Deaveraging of Distribution Rates. One important issue discussed by the participants was what might occur if distribution rates were deaveraged and the integrity of existing distribution service territory were not maintained. In such a scenario, the Cooperatives, and low-income advocates were concerned about how the disparity of distribution costs and rates between two competing - and possibly contiguous - companies could result in customers ultimately buying from a company that did not provide the lowest generation costs. That is, a vertically integrated utility serving an urban area would generally have a lower distribution cost than a rural utility with relatively few customers per mile of distribution. If the urban utility is permitted to collect distribution costs on a "rolled-in" basis from all of its customers, it can offer the full package of services (generation, transmission, and distribution) at a lower total price per kWh than can its rural counterpart, even if the rural utility was "made whole" by the urban utility paying the rural utility the full costs of the rural utility's unbundled distribution. This could even be the case despite lower generation costs on the part of the rural utility, depending upon the extent of the disparity in average distribution costs.

One solution that was discussed was requiring the competitive supplier (in this case the urban integrated utility) to charge the customer it is servicing in the rural utility's service territory the full distribution rate that the rural utility had historically charged. This solution could work provided that the urban utility's native customers do not absorb any of the distribution costs of the rural utility, essentially maintaining the integrity of each existing service territory. This solution would require strong segregation of costs, and records that maintain the segregation of customers by existing service territory.

A related issue is the geographic deaveraging of rates (an emerging trend in the telecommunications industry) within a utility's existing service territory. Presently, with average distribution costs and pricing, the more rural customers in a service territory are effectively subsidized by the more urban customers. Deaveraging geographically could result in rural customers seeing higher rates (to an unknown extent) as the subsidy from the more urban customers is lost.

IV. SYSTEM BENEFITS CHARGE

Through various rate cases and through the Integrated Resource Planning decisions, the Commission has required incumbent utilities to conduct a series of low-income, environmental, demand-side management (DSM), and renewables programs. For those utilities with nuclear plants, the Commission has required nuclear power plant decommissioning programs. These programs will, at least in the short run, increase these utilities' costs, thereby driving their prices up at the margin.

With the advent of retail electric competition, it is likely that the incumbent utilities will be unable to meet the Commission-mandated requirements and still remain competitive as customers select new electricity providers. The System Benefits Charge was developed to ensure that customers who select a new electric service provider will continue to contribute to these public interest programs, thereby allowing their distribution utility to meet mandated requirements and to fairly compete for customers as Arizona transitions into a competitive market. Staff asserts that the original intent of the System Benefits Charge was to ensure that departing customers will pay the same amount (on a per kWh basis) for these programs as the customers who remain with the incumbent utility.

A. AREAS OF AGREEMENT

1. ISSUE: DSM Portion of the System Benefits Charge. The Working Group agreed that DSM measures that are already market driven should not be included in programs that are funded by the System Benefits Charge. Which programs are market driven can be determined during review of the triennial System Benefits Charge filings discussed elsewhere in this section. The Working Group agreed that the DSM portion of the System Benefits Charge should include those programs that are designed to reduce or overcome market barriers to market driven energy efficiency that are not otherwise addressed adequately in competitive or regulated markets.

2. ISSUE: Nuclear Decommissioning Portion of the System Benefits Charge. The Working Group agreed that nuclear decommissioning charges should be entered as a separate line item of the System Benefits Charge. However, one issue that was presented in the Stranded Cost Working Group and not discussed by the Unbundled Services Working Group was the issue of nuclear waste disposal and whether that should also be part of the System Benefits Charge. To the extent that it is, a change to the rule would be necessary.

3. ISSUE: Amounts Collected Annually through the System Benefits Charge. The present language in the rule lends itself to differing interpretations. The sentence in question says (R14-2-1608.A):

"The amount collected annually through the System Benefits charge shall be sufficient to fund the Affected Utilities' present Commission-approved low income, demand side management, environmental, renewables, and nuclear power plant decommissioning programs."

One way to interpret the language is that it means the actual dollar amounts presently (i.e., at December 26, 1996, the date the rule was approved) included in regulated rates are sufficient to fund the programs covered by the System Benefits Charge language. The rules clearly state that the System Benefits Charge should be enough to fund the "present Commission-approved" programs. If the Commission approves additional programs in the future, R14-2-1608.A. says "the Affected Utility may file for a change in the System Benefits charge at any time."

It was observed that it will be difficult, if not impossible, for the State's two largest utilities to achieve the renewable resource goals identified in the Integrated Resource Planning (IRP) at present funding levels. Moreover, there are several DSM programs under way that had not been submitted to the Commission for approval until after the Retail Electric Competition Rule was approved in December 1996. These examples conflict with the first interpretation.

Accordingly, a second interpretation of the language is that amounts collected by the System Benefits Charge should be sufficient to fully fund the programs supported by the SBC, regardless of the December 1996 funding level. This interpretation addresses the adequacy of amounts presently included in regulated rates. It may result in amounts collected on a per kilowatt-hour basis through the System Benefits Charge, applicable to retail customers in the competitive market, greater than those collected through regulated rates.

After much discussion, the Working Group concluded that the ambiguity might be resolved by adding new wording to the rule to set up a mechanism for establishing the proper level of the System Benefits Charge. The following wording change was suggested as a way to clarify the wording in the rule. (New wording is underlined twice.)

In addition, the Affected Utility may file for a change in the System Benefits Charge at any time. Affected Utilities shall file for a review of the System Benefits Charge every three years. The amount collected annually through the System Benefits Charge shall be sufficient to fund the Affected Utilities' present Commission-approved low income, demand side management, environmental, renewables, and nuclear power plant decommissioning programs in effect from time to time.

This rule change, if adopted, would establish a mechanism by which the level of SBC funding is reevaluated. Through this mechanism, advocates of a set level of funding as well as those who argue that funding should correspond to a set need will periodically have the opportunity to make their case to the Commission.

4. ISSUE: Low Income Portion of SBC. The Rule provides for low-income programs under the System Benefits Charge. Utilities currently provide low-income programs designed to make electricity more affordable and accessible for low-income consumers.

These programs include rate discounts, bill assistance, weatherization and energy education and vary from utility to utility in type and funding level.

The Working Group was unable, due to time restraints, to determine how low income programs should be provided for during the phase-in period or under full competition including:

• Uniform menu of types of programs
• Statewide versus local distribution territory administration of programs.

Therefore, the Working Group recommends that low-income issues be addressed in the coming months.

1. AREA OF DISAGREEMENT

ISSUE: Administration of System Benefits Charge. One significant area of disagreement among the Working Group members concerned administration of the System Benefits Charge. The two alternatives presented were for an independent system administrator and for incumbent utilities to administer the funds. {At the final meeting of the Working Group, it became clear that there may have been a misunderstanding of the suggested "independent administrator." Those who have proposed an "independent administrator" indicated that this entity would not provide SBC services or implement programs, but rather, merely administer the SBC funds. Those interested in pursuing possible independent administrator approaches can raise this issue as the Commission considers the appropriateness of System Benefit Charge filings by Affected Utilities. }

Those advocating an independent Systems Benefits Administrator assert that an independent administrator could more effectively manage System Benefits Charge money. They contend that utilities have high overhead costs and inherent conflicts of interest. They believe that such an administrator could reduce overhead costs and would operate without conflicts of interest.

Those arguing for utility administration of programs say that if System Benefits Charge money is diverted to another organization, there will be a shortfall of funding for Commission-ordered programs. They contend that utility programs are well-established and far along the "learning curve." A new provider of services would have to start anew. Utilities assert that there are inherent benefits to customers by the management of distribution costs through DSM. Finally, there is a concern that the Commission may have difficulty controlling independent organizations which are not subject to the Commission's regulatory authority.

Staff recommends that, if the Commission decides to allow an independent SBC administrator, that the Commission relieve the affected utilities from the existing, related Commission requirements to perform such programs and provide such services. Further, Staff recommends that if the Commission decides to move to an independent SBC administration, that it be done over a reasonable transition period, to allow affected utilities time to efficiently transfer existing programs to the new independent administrator.

If the Commission were to opt for an independent SBC Administrator, the party making the triennial filing would change from the affected utility to the administrator, for certain of the programs mentioned.

The question of new programs under the System Benefits Charge was raised. Those in the minority position on including solar thermal water heating in the Solar Portfolio Standard Subcommittee have been told that solar water heating was not forgotten when Staff drafted the Rules, but was meant to benefit under the System Benefits Charge. The Working Group generally agreed that solar thermal water heating should be allowable under the System Benefits Charge. Since there are not currently any programs that benefit solar thermal water heating, new programs will need to be developed and a mechanism to approve these programs needs to exist.

V. MEASUREMENT/COST ISSUES

How costs are handled in the new competitive environment will have an important impact on the success of competition and on the limitation of potential anti-competitive abuses. The Working Group discussed numerous aspects of measurement and cost issues.

1. AREAS OF AGREEMENT

1. ISSUE: Categorization of Costs. When tariffs are filed for Standard Offer and Unbundled Services, it is Staff's responsibility to ensure that the rates (for non-competitive services) are cost based, and that such rates do not include costs associated with the provision of competitive services. In this regard during the transition to retail competition, Staff should guard against the shifting of costs from competitive generation to distribution, transmission or standard offer generation.

There should be no incentive for companies to load additional costs into competitive service offerings since that would cause the pricing to increase and thereby make the offeror's unbundled service or service elements less competitive. When reviewing those tariffs, Staff will also look to ensure that rates cover costs to prevent predatory pricing by any firm with market power.

Finally, it is important to note that interested parties may petition to intervene in tariff filings. Even without intervention, interested parties may file comments on any tariff filing. With intervention, if a particular tariff filing went to hearing, intervenors would have the same rights as parties and could present their own evidence and cross-examine witnesses.

2. ISSUE: Cost Basis: Historical or Marginal.

• Standard Offer Service - Tariffs for Standard Offer Service are not required to be filed under the Rules; Affected Utilities may leave their existing tariffs in place. To the extent that an Affected Utility chooses to file new tariffs for Standard Offer Service, the same costing principles would apply to that filing as have historically applied to the other filings of monopoly utilities.
• Unbundled Services - For unbundled service offerings, where a measure of competition will exist, rates should approach cost, and marginal cost pricing will probably be used.

• ISSUE: Preventing Cost-shifting. In the review of any tariff or in a rate case, part of the Staff's analysis is to ensure that the rates for noncompetitive services should be cost-based and such rates should not include costs associated with the provision of competitive service. Affected Utilities are, however, free within the parameters set forth in the previous sentence to file to rebalance their rates.

• ISSUE: Predatory Pricing. Predatory pricing { Predatory pricing is reducing prices below cost in order to drive a rival out of business or prevent new rivals from emerging with the intention of raising prices afterward to recoup all losses.} is offering a service below cost to obtain market power. Predatory pricing is not an issue if the rates charged for a service or product cover costs. That will be part of the Staff's review of any tariff. If competitors believe that a predatory pricing situation is taking place, they may file a complaint with the Commission, and that well-developed process will be followed.

8. ISSUE: Non-Discriminatory Pricing. R14-2-1606.C. states that the Unbundled Service tariffs must be offered on a non-discriminatory basis. That is, the price, of services such as distribution and transmission should be comparable for similarly-situated customers, irrespective of whether the customer purchases competitive services from the utility as part of Standard Offer Service, a utility affiliate, or a third-party provider. Failure to require non-discriminatory treatment could result in the creation of market power for utility-provided or affiliate-provided generation, as the price of non-competitive services could conceivably be set at a higher level for customers purchasing generation from third parties.

B. AREA OF DISAGREEMENT

ISSUE: Marketing Costs. There was significant discussion in the Working Group concerning marketing costs. Some felt that Affected Utilities should cease competitive marketing activities at the end of 1997. Some potential competitors felt that Affected Utilities should be required to clearly demonstrate, in their December 1997 filings, that marketing costs associated with competitive services have been removed from regulated rates. It was also suggested that Affected Utilities should be required to file information about establishment of an affiliated, competitive marketing entity. Finally, it was suggested that the Commission should adopt guidelines concerning the relationships between the Affected Utilities and their affiliated, competitive marketing entities.

Staff believes that the existing process is adequate and that no change to the rules are necessary. Staff will review tariffs filed for Standard Offer Service and noncompetitive unbundled services to ensure that marketing costs that support competitive services are not included in the pricing. There is no incentive to put excessive marketing costs into competitive service offerings since that may make an offering noncompetitive in the market. Additionally, establishing an affiliated entity would require compliance with the interest rules where the general standard for allowing a utility to establish an affiliate is that it causes no materially adverse impact on the utility.

VI. SOLAR PORTFOLIO STANDARD

A. BACKGROUND

The Commission has supported development of renewables by utilities in Arizona for a number of years. In the first two cycles of Integrated Resource Planning (IRP), the Commission encouraged Arizona utilities to diversify their generation mix by adding renewable resources. Very little in renewable resource generation has resulted from the IRP orders. Now, through the Retail Electric Competition Rule, the Commission has required that all Electric Service Providers must provide part of their competitive electricity from solar.

1. Staff Analysis of the Solar Portfolio Standard

Solar electric technologies are the most applicable renewables in Arizona. The phase-in program extends the Commission's interest in renewables by requiring that suppliers in the competitive market obtain at least one half of one percent of the total retail electric energy sold competitively from solar resources, whether that solar energy is purchased or generated by the seller. Solar resources include photovoltaic resources and solar thermal resources (for example, dish-Stirling generation). After December 31, 2001, the Commission may change the solar portfolio percentage; if it does not act, the percentage increases to one percent of electric energy sold competitively.

Solar resources may be built and operated by sellers of electricity in the competitive market. However, it is expected that some of the solar energy will be supplied by firms specializing in solar resources that sell their electric output to competitive suppliers under contract. The rule indicates that the solar resources must be new, i.e., installed on or after January 1, 1997. The purpose of the requirement is to foster advances in technology, encourage economies of scale in manufacturing, and gain greater experience with applying solar resources. Sellers must report regularly on their compliance with the standard; they must clearly demonstrate the output of solar resources, the installation date of solar resources, and the transmission of energy from those solar resources to Arizona consumers.

The rule encourages early development of solar resources through a "double credit provision." Any company certificated under the provisions of the rule can credit two times the electric energy generated before January 1, 1999 using solar electric resources installed in Arizona on or after January 1, 1997 to the percentage requirement cited above.

Competitive market consumers and suppliers will pay for the solar portfolio standard. The costs will be shared by both consumers and suppliers reflecting the price elasticities of demand and supply. Further, among consumers, a large share of the costs are likely to be borne by those competitive market consumers who desire "green power." That is, those consumers who value solar power the most are likely to bear a large fraction of the costs of the Solar Portfolio Standard and they will satisfy their demand for solar electricity. In another section of the Retail Electric Competition rule (R14-2-1604 E3) there is a provision that allows customers who receive at least 10% of their electricity from solar resources to be automatically eligible for competitive electric service.

The percentage standard was selected in order to balance the interest in encouraging solar power and the higher costs of solar power relative to conventional generation. The cost impact of the solar portfolio standard is expected to be smaller than the savings which can occur through competition, especially as stranded cost recovery concludes.

With a solar portfolio standard of 0.5 percent and with 20 percent of the market served competitively, about 21 MW of solar generation capacity would be needed if SRP is included; if SRP were excluded, solar generation requirements would be about 13 MW.

The percentage standard is consistent with the utilities' planned generating capacity additions, as reported in the 1995 Resource Planning filings. By 2003, the year full competition is to start, the utilities have planned to add 377 MW of generating capacity; by 2004 they have planned to add 602 MW of generating capacity. These figures should be regarded as estimates. Including SRP, a solar portfolio standard of 1 percent of competitive kWh sales would result in solar capacity additions of 256 MW by 2004. The solar generating capacity would be in addition to the renewable goals established for utilities in the most recent Integrated Resource Planning order.

There are four solar technologies that could meet the needs of competitors in the Arizona phase-in: photovoltaics, solar dishes, solar troughs, and solar central receivers.

In developing the details of the Solar Portfolio Standard, the Corporation Commission Staff was guided by the following objectives:

• Encourage the use of solar electric technologies to increase the fuel diversity in the electricity generation mix.
• Increase utility and electric service provider expertise and experience in the procurement, installation, and operation of solar electric systems or in the purchase and transmission of solar electricity from other sources.
• Encourage new solar electric technologies as a reasonable percentage (1/2 to 1% of competitive retail electric sales) that is significantly less than the annual growth (2-3% per year) of demand for electricity. (This allows utilities and other electric service providers free choice of the technologies for 99-99.5% of electricity generation.)
• Encourage the use of modest-sized, distributed solar generators to reduce the loading on existing transmission lines and also reduce the need to build new, expensive transmission lines as the demand for electricity increases in the future.
• Contribute to the commercialization of solar electric technologies, which will decrease the cost of solar electricity to Arizona customers in the future.

B. ACTIVITIES OF THE SOLAR PORTFOLIO STANDARD SUBCOMMITTEE

The Solar Portfolio Standard Subcommittee had its first meeting on May 8, 1997. The second meeting, on June 2, 1997, included a morning workshop and an afternoon meeting. Follow-up meetings were held on July 9, August 1, August 27, and September 12, 1997.

Prior to the first meeting, subcommittee members submitted 27 major issues of concern. At the first meeting, an additional 27 issues were identified. The subcommittee then grouped the 54 issues into eight major issue categories:

1. Major Issue Categories Related to the Solar Portfolio Standard:

• Goals and objectives of the SPS
• Technology choice (definition of equipment allowed in the Solar Portfolio Standard)
• Costs/timing
• Incentives (reward intended results, discourage unintended results)
• Economic development/solar industry development
• Administration
• Level playing field
• Technical details

• Objectives. The Subcommittee discussed objectives developed by Staff and, at the August 1 meeting, the Subcommittee developed additional objectives for the Solar Portfolio Standard and slightly modified the wording of the original Staff objectives:

• Encourage the use of solar electric technologies to increase the fuel diversity in the electricity generation mix.
• Increase utility and electric service provider expertise and experience in the procurement, installation, and operation of solar electric systems or in the purchase and transmission of solar electricity from other sources.
• Encourage new solar electric technologies as a reasonable percentage of competitive retail electric sales that is significantly less than the annual growth of demand for electricity.
• Encourage the use of modest-sized, distributed solar generators to reduce the loading on existing transmission lines and also reduce the need to build new, expensive transmission lines as the demand for electricity increases in the future.
• Contribute to the commercialization of solar electric technologies, which will decrease the cost of solar electricity to Arizona customers in the future.
• Contribute to economic benefits throughout Arizona.
• Encourage environmental benefits.
• Encourage a market-based solar electric industry.
• Increase public information/awareness of solar electricity.
• Reach an acceptable cost/benefit point.
• Encourage solar resource development, rather than payment for non-compliance.

• Suggested Changes to the Solar Portfolio Standard:

Subcommittee members were asked to suggest ideas for changes to the Solar Portfolio Standard. The following suggestions were made by various Subcommittee members:

Arizona Electric Power Cooperative, Inc. (AEPCO) said that the Solar Portfolio Standard is unduly burdensome and that both AEPCO and its members should be excluded from the requirements. AEPCO and its members do not need any new generation until after the turn of the century. The cooperatives are non-profit and member-customer owned who have no shareholder venture capital to invest in expensive excess capacity. AEPCO does not believe an investment in solar resources according to the SPS timetable would benefit the member-customers that the member-owner cooperatives serve. AEPCO proposed, as an alternative, a portfolio standard that could be phased in as new generation resources are needed to serve the retail competitive load. It should also be noted that, as a precedent, the Nevada Legislature in its competition rules exclude cooperatives from its SPS.

Arizona Public Service Company (APS) suggested that the Solar Portfolio Standard should encourage the local economic development of the solar industry. APS suggests the establishment of a "wires" charge of 30 cents for each solar kWh required for the solar standard, which can be offset, i.e., reduced, by 30 cents for each solar kWh actually provided by the ESP. This avoids the problems with penalties, and assures that the money will be spent on solar and encourage competition to purchase solar energy in the market at the least price available below 30 cents. The charges for solar kWh requirements that are not offset by the ESP would be paid to the regulated "wires" companies for them to purchase solar kWh, or install solar to meet the kWh requirement. If the cost of solar kWh to the "wires" companies exceeds 30 cents, the companies would obtain the maximum kWh possible with the funds. The wires companies would resell the solar kWh and use the revenues to offset or reduce wires charges in the future. This approach would also provide a limit to the cost of the SPS. The .5% portfolio requirement should be kept until 2003 and increased by .1% each year thereafter, until reaching 1% in 2008. A 2-times credit should be given for solar kWh from equipment manufactured and installed in Arizona. The double credit should be good for five years and apply to plants installed through 2008.

ElectriSol Ltd. recommended minor modifications in the gradation of the Solar Portfolio Standard over time to produce (in conjunction with the major step increases in eligible customers in 1999, 2001, and 2003) a more gradual solar increase over years and increasing above 1% in later years. SPS % suggestions were: 1999: .5%; 2000: .75%; 2001: .5%; 2002: .75%; 2003: .5%; 2004: 75%; 2005: 1%; 2006: 1.25%; 2007: 1.5%.

The Arizona Solar Energy Industries Association (ARISEIA) recommended that solar water heaters be included in the Solar Portfolio Standard.

KJC Operating Company recommended that the Solar Portfolio Standard not be limited to modest-sized solar installations. KJC feels that the SPS % should be increased to 1% in 1999 and, after that, increased by at least .5% per year for at least five years.

The Land and Water Fund of the Rockies suggested that a way needs to be found to allocate penalty monies to the installation of solar equipment, possibly in conjunction with the System Benefits Charge programs, rather than having the penalties go back to the General Fund.

Solel Solar Systems Ltd. said that there is a minimum "critical mass" for solar projects of 30-35 MW.

Entech, Inc. suggested rule clarification that would "grandfather" solar systems already installed or solar electricity already contracted for, if the Commission decided at a later date to drop the SPS requirement. This would avoid stranded solar investment.

A Tucson Electric Power Company (TEP) representative suggested starting with a lower SPS% of 1/4 of 1%, increasing to 1/2 of 1% in 2003, 3/4 of 1% in 2005, and 1% in 2007, assuming that the competitive phase-in currently contemplated by the Rules were to be changed in favor of a flash-cut (i.e., 100% competition starting at once) in 2001. TEP suggested adding a credit for solar "Competitive Suppliers" who own or invest in solar manufacturing, system integration, or similar businesses in Arizona. TEP also suggested double credit for early installations.

Enron presented a detailed proposal that would incent parties to enter into power purchase agreements of various terms. To hedge pricing risk associated with such contracts, Enron outlined a series of incentive credits for generated kWhs with larger credits for longer power purchase agreement terms. To the extent that the market share fluctuations and incentive credits create shortages/surpluses of kWh credits, Enron proposed allowing the trading of credits. Enron also recommended that the penalty should be increased to 50 cents per kWh to discourage participants from simply deciding to pay the lower 30-cent penalty. Given the reluctance of energy providers to enter into long-term agreements, the higher prices of "spot" or short-term solar energy make the current penalty more appealing than a penalty should be. Enron further recommended that any penalty funds be used to buy down the consumer cost of purchasing distributed solar generation, including solar rooftop systems. To enhance the economic appeal of these rooftop systems, Enron proposed that legislation promoting net metering at retail rates be implemented. Enron believes that the Solar Portfolio Standard should not include DSM, energy efficiency, or other renewable technologies. Enron also recommended that certain technical solar standards and a certification of solar facilities be met by all solar providers.

Both Boeing and York Research Corporation recommended keeping the Portfolio Standard as originally adopted.

Stirling Energy Systems, Inc. recommended that the 1% requirement should be gradually increased to 5% by January 1, 2008.

ASARCO, BHP Copper, Cyprus Climax Metals, Phelps-Dodge, and the Public Interest Coalition on Energy (the Mines and the Coalition) object to the imposition of the solar portfolio mandate. The Solar Portfolio mandate will hamper the implementation of retail competition by increasing retail prices and by adding supply-risk to the provision of competitive resources.

4. Spreadsheet Analyses of Solar Options. Thanks to funding from the National Renewable Energy Laboratory (NREL), a consultant to NREL, Pacific Energy Group, was able to develop a sophisticated spreadsheet tool to evaluate five options that had been suggested for the Solar Portfolio Standard. A representative of Pacific Energy Group (PEG) made a presentation to the Subcommittee at the August 27 meeting. Based upon input from the Subcommittee, PEG refined the spreadsheet and it was e-mailed to Subcommittee members on September 4, 1997.

5. Energy Efficiency and Renewable Energy Economic Development Impact Study. Several Subcommittee members attended a workshop presented by Economic Research Associates that described the results of a study jointly funded by the National Renewable Energy Laboratory, the Land and Water Fund of the Rockies, and the Arizona Department of Commerce Energy Office. The Study, called "Arizona Energy Outlook 2010: Energy Efficiency and Renewable Energy Technologies as an Economic Development Strategy," presents a scenario that recommends a $4.8 billion cumulative investment for energy efficiency and renewables for years 1998-2010. Such an investment, representing less than .3% of Arizona's cumulative GSP for the period, would result in energy bill savings of almost $2 billion, generates a positive benefit-cost ratio of 1.92 and creates 11,100 new jobs.

C. AREAS OF AGREEMENT

In its deliberations, the Solar Portfolio Standard Subcommittee developed some areas of agreement.

1. ISSUE: Changing the Penalty Provision in the Standard. The Subcommittee agreed that the penalty provision in the rule was inappropriate, as written. As written, the penalty funds would not ensure the installation of any new solar electricity projects. The penalty funds would return to the General Fund of the State of Arizona. This would not promote the widespread use of solar electric technologies by electric service providers as intended by the Solar Portfolio Standard. The Subcommittee agrees that the penalty wording should be changed to a mechanism whereby the penalty funds are utilized to install solar electricity systems in Arizona.

2. ISSUE: Incentives. The Subcommittee agreed that the Solar Portfolio Standard should include incentives of some type to encourage the electric service providers to take actions which will better meet the objectives of the Solar Portfolio Standard. There is general agreement that the incentive in the existing rule is not substantial enough to encourage a significant number of early solar installations.

3. ISSUE: Banking and Trading of Solar kWh. The Subcommittee agreed that Electric Service Providers should be allowed to "bank" or save up any extra (that is, above the annual portfolio requirement) solar kWh produced in a year for use in later years. The Subcommittee agreed that excess solar kWh should be tradable commodities that may be sold to other interested parties.

4. ISSUE: Cost Reduction Incentive. The Subcommittee agreed that the cost of the Solar Portfolio Standard should be limited to an acceptable cost/benefit point, and a cost-reduction incentive should be provided to protect Arizona consumers from increasing solar purchases if lower-price objectives are not met. A kWh cost-impact cap could be set to insure that costs must decline in order for solar installation rates to increase. If the kWh cost-impact cap is broadly accepted and achieved, it could help provide a reasonable expectation for the solar industry that the Solar Portfolio Standard requirement would remain or could even increase. This range and the related assumptions and uncertainties would need to be considered in determining an acceptable cost-impact cap. Other measures such as the average solar installed cost and performance should be monitored as well. The Subcommittee agreed that the Commission should establish a mechanism to develop the cost-impact cap and decide on a date when the costs of solar electricity is to be compared to the cost-impact cap. This "decision point" would be used by the Commission to determine if the Solar Portfolio Standard percentage should change.

D. AREAS OF DISAGREEMENT

1. ISSUE: Allowable Technologies in the Solar Portfolio Standard Definition. The issue is whether the Solar Portfolio Standard definition should be expanded to include renewables other than solar electric systems. Some Subcommittee members suggested including other renewable technologies, such as wind, biomass, or geothermal, in the definition. Representatives of the Arizona Solar Energy Industries Association suggested expanding the definition of solar equipment eligible for the Solar Portfolio Standard by adding the following wording to the definition: "or displace electricity by active or passive solar thermal energy technologies."

• Majority Opinion: The Solar Portfolio Standard definition should stay as it is: requiring the use of solar electric technologies. This will increase fuel diversity in the electricity generation mix. It will increase electric service provider expertise in using solar electricity systems. By concentrating on four solar electric technologies, the Solar Portfolio Standard will contribute to the commercialization of those four technologies in a major way. This concentration will lead to manufacturing expansions which will reduce the future costs of electricity produced by solar. Focusing on solar electric technologies is more consistent with the business in which electric service providers operate. The "portfolio" to which the standard refers is the provision of electricity. Adding a long list of other "renewable" technologies would dilute that commercialization effort.

Renewables other than solar electricity, such as wind or solar water heating (SWH), should not be included in the SPS. Wind resources are not widely available in Arizona, and are poorly matched in time and location to the daily and seasonal electric load of the state. Wind is already in large-scale use and is well supported in other states that have more wind resources. Water heating provides thermal energy, which is a totally different product than electricity, measured in thermal BTUs, which have a much lower value and cost than electric kWh. Solar water heaters are devices that normally must be installed as part of a customer's water plumbing and heating system and their cost-benefits are better handled by companies that sell equipment and services for energy savings. Finally, it was recognized that there was another mechanism in the rules, the System Benefits Charge, which allows the use of all other renewable technologies that were suggested for inclusion in the definition. The majority felt that the System Benefits Charge was the proper mechanism to encourage solar water heaters and other renewables. Any incentives for wind, solar water heating or other renewables should be considered separately, under the System Benefits Charge. (ElectriSol, Tucson Electric, R. Annan, Boeing, LAW Fund, Enron, Stirling Energy Systems, Arizona Public Service Company, USSC, KJC Operating Company, PVRI, PowerMark, City of Tucson, American Hydrogen Association)

• Dissenting Opinion(s): Solar water heating should be included as part of the Solar Portfolio Standard. Solar water heating does produce BTUs, which can be expressed in electric terms by the following simple formula: 3250 BTUs = 1 kWh. Meters are available that make this calculation. Like other solar technologies, the cost of solar water heating would decrease significantly if used on the scale expected to be created by the SPS. Unlike other solar technologies, solar water heating panels are presently manufactured in Arizona and other manufacturers have indicated that they would open facilities here if solar water heating were included in the SPS. Solar water heating is by far the most economical solar technology. A standard solar water heater, which costs approximately $2,500 offsets as much electricity in a year as $20,000 photovoltaic would. That is obviously a substantial difference.

Unlike the other solar technologies, such as central receiver, Stirling dish, or central station photovoltaic, solar water heating will be located at the home of the residential user instead of a remote location. At this home location, it will produce a direct observable benefit to that consumer immediately. In addition, the "majority opinion" is seriously compromised since those who comprise the majority stand to lose financially if it is included. The only winners would be residential users. It gives them five to ten times the amount for their money. The only state with similar conditions with a Solar Portfolio Standard, Nevada, included solar water heating in its renewable standard. (Arizona Solar Energy Industries Association, Entech, York Research Corporation, AEPCO, Conservative Energy Systems, SAIC, Solar Energy Industries Association, Bechtel)

• Individual Dissenting Opinion(s):

a. A provision for solar water heating and other renewable technologies could be incorporated after the year 2003, assuming there is an increase of an additional 4% of the total electrical power generation for renewables in Arizona. (Stirling Energy Systems, American Hydrogen Association)

b. Pacific Energy Group joins with the dissenting opinion under the following conditions: If solar water heating were allowed in the SPS, then:

(i) It should be allocated a maximum percentage of the SPS to address concerns of diluting commercialization efforts of competing solar electric technologies. We suggest a maximum percentage of 15%. This does not mean that 15% of the SPS is reserved for solar water heating, it means that solar water heating is eligible to fulfill up to 15% of the SPS on a per Energy Service Provider basis;

(ii) The definition of eligibility should be more strictly defined. For example, replace the dissenting opinion language to read, or solar hot water systems that directly displace electricity used to heat water; and

(iii) Solar hot water systems that qualify under the SPS shall not be eligible for other funds resulting from restructuring, such as a system benefits charge, only if other technologies such as troughs, towers, dishes, and PV are similarly ineligible. (Pacific Energy Group)

2. ISSUE: Solar Portfolio Standard Percentage and Timing. The issue relates to the size of the Solar Portfolio Standard percentage and how that should change over time. Some feel that the percentage is too high in the early years, when solar is more expensive. Others feel that the timing of the phase-in should be extended.

• Majority Opinion: The majority of the Subcommittee members believe that either the percentage should be changed, or, by the use of multiple-credit incentives, the "effective percentage" should be reduced. (The "effective percentage" idea relates to the idea that a double credit, for instance, will effectively temporarily reduce the percentage to one-half of the required amount, though the full amount would be built after the credit expires.) There is no majority agreement on what the percentage should be. There also is no majority agreement on when the percentage should be increased.

Some of the suggested changes mentioned are:

• Mixed Opinions:

1. The .5% portfolio requirement should be kept until 2003 and increased by .1% each year until reaching 1% in 2008. (Arizona Public Service Company, AEPCO, Tucson Electric)

• Dissenting Opinion(s):

1. Some members of the Subcommittee felt that the Solar Portfolio Standard percentage and timing should remain as written in the rules. No change is needed. (Boeing, York Research Corporation, R. Annan, LAW Fund, Solar Energy Industries Association, USSC, City of Tucson)

3. ISSUE: Incentives.

• Majority Opinion: The majority of the Subcommittee members agree that some sort of incentives should be incorporated into the Solar Portfolio Standard. The majority agree that two different incentives should be offered: one incentive to encourage early installation of solar electric systems and another incentive to encourage solar economic development in Arizona:

a. Early Installation Extra Credit Multiplier: For new solar electric systems installed and operating prior to December 31, 2003, electric service providers would qualify for multiple extra credits for kWh produced for five years following operational start-up of the solar electric system. The five-year extra credit would vary depending upon the year in which the system started up, as follows:

YEAR

EXTRA CREDIT
MULTIPLIER

1997

.5

1998

.5

1999

.5

2000

.4

2001

.3

2002

.2

2003

.1

The Early Installation Extra Credit Multiplier would end in 2003.

b. Solar Economic Development Extra Credit Multiplier: There are two equal parts to this multiplier, an in-state installation credit and an in-state content multiplier.

1. In-State Power Plant Installation Extra Credit Multiplier: Solar electric power plants installed in Arizona shall receive a .5 extra credit multiplier.

All multipliers are additive, allowing a maximum combined extra credit multiplier of 1.5 in years 1997-2003, for equipment installed and manufactured in Arizona. So, for example, if an Electric Service Provider installed a solar power plant in 1999 in Arizona, using 100% Arizona content, which produced 1 million kWh, the ESP would receive credit for 1 million kWh plus extra credit of 1.5 million kWh, totaling 2.5 million kWh.

(Pacific Energy Group, Bechtel, SAIC, USSC, Enron, Solar Energy Industries Association, KJC Operating Company, Stirling Energy Systems, American Hydrogen Association)

Some of the suggested incentives are:

• Mixed Opinions:

1. The Solar Portfolio Standard should encourage the local economic development of the solar industry. A 2-times credit should be given for solar kWh from equipment manufactured and installed in Arizona. The double credit should be good for five years and apply to plants installed through 2008. Economic development incentives are fully described in Issue 4. (Arizona Public Service Company, Tucson Electric, AEPCO, R. Annan, City of Tucson)

1. Double credits for early installations and credit for competitive suppliers who invest in solar manufacturing, systems integration, or similar businesses in Arizona. (Tucson Electric)

• Dissenting Opinion(s): Some of the Subcommittee members feel that no changes to the Solar Portfolio Standard are needed. (Boeing, ElectriSol, and York Research Corporation)

4. ISSUE: Economic Development Incentives.

• Majority Opinion: A majority of the committee agreed that the SPS should be modified to enhance its economic benefits for Arizona consumers. The present rule does not contain a mechanism to specifically encourage the long-term development of the Arizona solar industry, or for installations of solar in Arizona. Arizona consumers who subsidize solar under the SPS are likely to expect substantial economic benefits from the resulting development of the solar industry. The majority agreed to a two-part economic development incentive (as shown in Issue C.) that offers incentives for in-state power plant installation and in-state solar equipment manufacturing. (Arizona Public Service Company, ElectriSol, Bechtel, Tucson Electric, R. Annan, York Research Corporation, AEPCO, Stirling Energy Systems, SAIC, USSC, Enron, City of Tucson, KJC Operating Company, American Hydrogen Association)

• Additional opinion(s):

1. Credit for competitive suppliers who invest in solar manufacturing, systems integration, or similar businesses in Arizona. TEP suggests that a Competitive Supplier should be entitled to receive a credit against the Solar Energy Requirement if the Competitive Supplier owns or otherwise makes an investment in any solar energy-related manufacturing, systems integration, or other similar business enterprise for which physical facilities are located in the state of Arizona. TEP proposes that any such credit against the Solar Energy Requirement will be equal to the amount of nameplate capacity produced in a calendar year times 2,190 hours (based on an assumption of 25% capacity factor for solar energy generation). Any assumptions and standards related to the determination of the Solar Energy Requirement could be adjusted by the Commission from time to time to reflect changes in the cost and operation of solar technology and related market conditions. (Tucson Electric, Bechtel)

• Dissenting Opinion(s): Some Subcommittee members believe that the Solar Portfolio Standard is not an appropriate place to have economic development incentives. Manufacturers will make plant location decisions based on other considerations and not on market issues such as those in the Portfolio Standard. (Boeing, Solar Energy Industries Association)

5. ISSUE: Protection for Electric Service Providers in Case of Future Commission Changes in the Portfolio Standard Requirement. One of the major barriers to the Affected Utilities and Electric Service Providers meeting the Solar Portfolio Standard is that, in the future, the Commissioners may decide to change or eliminate the Solar Portfolio Standard. This might leave the early participants at a competitive disadvantage.

• Majority Opinion: A rule clarification was suggested that would "grandfather" solar systems already installed or solar electricity already contracted for, if the Commission decided at a later date to drop the SPS requirement. The majority agreed that some wording should be added to the rules to protect the participants from the adverse affects of a future change in Commission rules to reduce or eliminate the Solar Portfolio Standard. (ElectriSol, Tucson Electric, R. Annan, AEPCO, York Research Corporation, Bechtel, Boeing, LAW Fund, Stirling Energy Systems, Solar Energy Industries Association, SAIC, USSC, KJC Operating Company, American Hydrogen Association)

• Dissenting Opinion(s): The ACC Rule clearly presents the definition of stranded cost "as the value of all the prudent jurisdictional assets and obligations necessary to furnish electricity...acquired or entered into prior to the adoption of this Article, under traditional regulation of Affected Utilities... Alone, this definition should provide reason to reject any proposal to recover future stranded solar investment.

Additionally, the current amount of stranded cost recovery imposed by the ACC Rule is burden enough to customers. Imposing future increases in stranded cost recovery will continue to impede pure competitive pricing for customers. Furthermore, the assurance of future recovery of stranded costs associated with solar investments can lead to imprudent solar investment on the part of the ESP's, which the customers will be responsible for subsidizing if stranded costs are imposed.

Ultimately it will be all customers that will be negatively impacted if future solar stranded investments. will allow for recovery. We do not support a mechanism will impose additional costs to competitive electricity prices as a result of stranded investment in solar facilities. (Mines and Public Interest Coalition on Energy, Enron)

6. ISSUE: Details of the Penalty in the Standard. Although there was majority agreement that the penalty wording in the rule should change, there was no general agreement in how the penalty monies should be used or what the penalty level should be. Some of the ideas suggested were:

• Mixed Opinions:

1. Increasing the penalty to 50 cents per kWh to discourage participants from simply deciding to pay the lower 30 cent penalty deserves consideration since energy providers are unlikely to enter into long-term contracts that would offer energy pricing well below the current penalty level. While it is understandable that the Commission would like to set limits on solar power pricing in order to minimize the rate impact on consumers, the penalty is not the optimal mechanism to achieve this goal. Instead, the Commission should evaluate the various pricing scenarios that may occur if energy service providers buy spot solar power versus if they enter into longer term contracts and establish target prices for solar power over time.(Enron, ElectriSol, Boeing, LAW Fund)

• Dissenting Opinion(s):

1. Some organizations are firmly against increasing the penalty levels. (Mines and Public Interest Coalition on Energy, Bechtel, Stirling Energy Systems, American Hydrogen Association)

VII. METERING AND METER READING ISSUES

1. INTRODUCTION

On December 26, 1996, the Arizona Corporation Commission adopted Article 16, the rules for Retail Electric Competition in Decision No. 59943. In Rules R14-2-1605 and R14-2-1606(c).2, it was ordered that metering and meter reading services were to become competitive services. In Rule R14-2-1606(I), it was ordered that the Commission Staff should explore issues in the provision of Unbundled Service and Standard Offer Service. Staff was also ordered to submit a report to the Commission on the activities and recommendations of the Unbundled Services and Standard Offer Working Group (Working Group) sixty days prior to the end of the year.

On April 9, 1997, the first meeting of the Working Group was held. The Objectives of the Working Group and the Key Issues were developed at this first meeting. At the next meeting of the Working Group on May 9, 1997, the participants began discussing the Key Issues. During these discussions, it became apparent that the implementation of the metering and meter reading issues would involve much more discussion. Thus, the participants agreed to establish a Metering Subcommittee. Representatives from Arizona Public Service (APS), Enron, Tucson Electric Power (TEP), Citizens Utilities, Sulphur Springs Valley Electric Cooperative (SSVEC), and the City of Tucson volunteered to be on the subcommittee. It was suggested that a consumer group such as the Residential Utility Consumer Office be invited to be a participant in the subcommittee. In addition, representatives from Salt River Project (SRP), Arizona Community Action Association (ACAA), Navopache Electric Cooperative (Navopache), CellNet Data Systems (CellNet), PG&E Energy Services, Energy Strategies, Inc. (ESI), Trico Electric Cooperative (Trico) and the City of Mesa joined the Subcommittee. David Jankofsky, chairman of the Working Group, appointed Commission Staff member Ron Franquero to head the Subcommittee.

B. ACTIVITIES OF THE METERING SUBCOMMITTEE

The first meeting of the Metering Subcommittee was held on May 28, 1997. The Subcommittee's objectives were to identify, discuss, and resolve metering and meter reading issues for the purpose of making recommendations to the Commission for incorporation in appropriate rule making. An initial list of 45 key issues regarding metering and meter reading was developed. The Subcommittee then summarized these key issues into ten major issue categories:

1. Meter Ownership

2. Who is responsible for what?

3. Protocols, Standards, and Procedures

4. Metering Requirements

5. Metering Services

6. Data Security

7. Data Communications

8. Data Management

9. Performance Standards

10. FERC Issues

After this first meeting, subsequent follow-up meetings were held on July 1, July 30, August 21, September 11, and September 26, 1997.

C. DEFINITION OF METERING AND METER READING SERVICES

At the August 21 meeting, a discussion was held on what part of metering and metering services should be open to competition and what part should remain regulated. This issue was further discussed at the September 11 and 26 meetings and the Subcommittee decided on the following definitions:

The following functions are included under the general heading "Metering and Meter Reading Services" (i.e., these functions would be open to competition under the existing rules).

1. Installation of meters.
2. Installation of instrument transformers, test switches, and wiring.
3. Maintenance and troubleshooting of all the above.
4. All other equipment (RTUs, recorders, communications) necessary to meet the requirements of specific customers' applications, when used primarily as billing/energy accounting tools.
5. Coordinate replacement and return of existing metering equipment.
6. The timely communication of all required metered data to all "authorized" parties.
7. Making customer data available to customers upon request.
8. Liability for "mis-metered" customers.
9. Automated Meter Reading systems including communication system.
10. Programming of solid-state meter registers.
11. The validation, editing, and estimation process to convert "raw data" to billing and settlement ready quality.
12. The provision of data storage and other data management services.
13. Maintaining security of metered data access.
14. Meter testing.
15. Provision of diagnostic services.
16. Physical disconnects and reconnects in the field.
17. Load research meters (Note: load research will be done by both the ESP and the LDC.)

Functions which DO NOT fall under this heading (these functions would continue to be regulated under the current rules):

1. Substation panel meters
2. Digital Fault Recorders
3. Remote Terminal Units used primarily for the operation, planning, and maintenance of transmission and/or distribution systems.
4. Any metering/monitoring equipment not specifically and primarily installed for billing and/or energy accounting functions.
5. Load research meters.

CellNet and Enron did not concur with the Subcommittee that competitive item #2 (installation of instrument transformers, test switches, and wiring) should be competitive. This equipment would only be needed for 400 amp service entrances and above or for 75 horsepower motors and above. CellNet and Enron were concerned that the high cost of this metering equipment would be a barrier for entry into the competitive market. At the September 26, 1997 meeting, it was mentioned that this metering equipment would only be installed for new customers. For existing customers, a service agreement could be made between the electric service provider (ESP) and the local distribution company (LDC) for use of the existing metering equipment.

CellNet and Enron also did not concur with the Subcommittee that item #16 (disconnects and reconnects) should be competitive. They felt that the LDC's should perform this activity to ensure consumer protection and because the Billing Subcommittee decided that LDCs would be the only one able to authorize physical disconnects and reconnects.

D. COMPETITIVE VERSUS REGULATED METERING AND METER READING SERVICES

Since the first meeting, considerable debate has occurred on whether metering and meter reading services should be made competitive. Rather than take too much of the Subcommittee's time, it was decided to have the participants present two "white papers" on this issue. TEP, then later APS, agreed to take the lead on preparing the paper on why metering and meter reading services should remain regulated. This paper is included as Appendix C. Enron agreed to take the lead on preparing the paper on why metering and meter reading services should become competitive. This paper is included as Appendix D.

E. AREAS OF AGREEMENT

In its deliberations, the Metering Subcommittee developed some areas of major agreement.

1. ISSUE: Meter Ownership. Initially, there was total consensus on this issue, but subsequently, some of the parties dissented. The original consensus was that the ownership and control of the metering equipment would be limited to the ESP or the LDC at the customer's choice. The LDCs such as APS and Navopache advocated this position. TEP indicated that the LDC or the customer could own the meter and Enron's position was that the ownership of the meter should be governed by the commercial agreement that is struck in the marketplace. This could include ownership by the customer, the ESP, or the Metering Agent (MA). CellNet and the Mines and Coalition indicated that anyone could own the meter, but the LDC or ESP should control the meter. In the United Kingdom, CellNet said the customer signs a service agreement with the LDC or the ESP. Problems could develop if the customer could own the meter, so the United Kingdom will require, beginning in 1998, that the energy provider be fully responsible for the meter, including its accuracy, integrity, data timeliness, and so on, regardless of who owns the meter. APS stated that certain problems of customer ownership, such as meter tampering and who is responsible for the operation and maintenance of the meter, could pose legal barriers to the customer ownership, or at the very least could involve added complexity. Despite these concerns raised by various entities, there was a consensus that meter ownership should be by the ESP or LDC.

2. ISSUE: Who Installs the Meters? The consensus was that the responsibility for the installation of meters rests with either the ESP or the LDC. It is a possibility that a metering agent (MA), a company who is hired by the ESP or LDC could handle the metering requirements, could perform meter installations.

3. ISSUE: What Part, if any, of the LDC's Metering Infrastructure (i.e., PTs and CTs, Meter Socket, etc.) Will be Made Available to Facilitate Third Party Installation of an Hourly Meter? Initially, there was complete consensus that the metering infrastructure (PT, CT, socket) would be transferred to the ESP with appropriate compensation to the LDC. Enron and CellNet changed their position and maintain that this metering equipment should remain as part of the LDC, notwithstanding that the PTs and CTs are an integral part of the meter and contribute to its accuracy. If the ESP takes over service to an existing LDC customer, it would be uneconomical to replace the existing metering infrastructure. Reimbursement for equipment will be worked out between the ESP and LDC based on an evaluation of the compensation process that must be developed.

4. ISSUE: If Metering is a Competitive Service, What Becomes of the Meter and Communication System Installed by an ESP When Its Contract Expires With the Customer? Is it Removed? How Does the LDC Get Its Metered Data Then? The consensus was that any transaction between two parties is a commercial (market) transaction. A timely procedure must be in place to ensure an orderly transition. Enron proposed that the customer could change his provider at any time of the month. APS was agreeable to this as long as there was enough time to change providers.

5. ISSUE: Should There Be a Provider of Last Resort For Metering and Meter Reading Services? The consensus was that there should be a provider of last resort for metering services. Today, electricity is a necessity of life, and there cannot be any point in the line of the generation, transmission, or distribution systems where a consumer could be left without service. At least three conditions will result in the need for a provider of last resort for metering and meter reading services:

There was consensus that the energy provider of last resort should be the metering provider of last resort. The Subcommittee deferred to the Working Group to determine who should be the energy provider of last resort. (See discussion in Chapter II.)

6. ISSUE: Metering Data Exchange. The delivery of data from the responsible MA to authorized recipient(s) of such data should be through a "connect to" server. The MA will maintain a database with validated and/or raw data in such a way that authorized parties can connect to the server and access the data. Whether or not two servers will be required, one for validated data and one for raw data, will require further analysis. The server will be constructed such that each authorized party will have access only to the data it is authorized to have. Access will be protected by password clearances to authorized data and the development of "firewalls" between communication and data servers. Other issues related to metering data exchange include the format of data, frequency of transferring data, and the method of communicating data to appropriate parties.

The consensus was that a statewide standard data file format must be implemented. Much discussion was held regarding the format to be used, but this issue will not be resolved until next year. A workshop should be held to help develop a statewide standard data file format.

Another consensus reached was that Arizona should adopt existing national standards. There is no need for the LDC's and the ESP's to invest in developing data communication systems and transaction sets when national standards already exist. There was no consensus reached on what national standard to use; however, Enron suggested use of an existing national standard (ANSI X.12) that was developed by the Utility Industry Group. These standards are called the Electronic Data Interchange (EDI). EDI is an off-the-shelf product that can be purchased for as little as $5,000 to $10,000. In addition, Arizona will benefit from the development and implementation of EDI in the California market.

There was also consensus for using the Internet as the preferred method of communications. TEP suggested that there are many reliability issues concerning the Internet and that the Internet is not reliable enough to trust it for critical real-time information.

7. ISSUE: What is the Minimum Metering Requirements to Accommodate Direct Access? Minimum metering requirements for direct access customers over 20 kW (or an annual equivalent kWh for 20 kW demand) should consist of hourly consumption measurement meters. This requirement is principally driven by the energy scheduling and settlement process (transmission ancillary services) which requires that hourly consumption data be accurately determined after the fact in order to assign transmission demand and ancillary services costs to those parties incurring such costs. All customers desiring direct access must have their loads pre-scheduled with the system operator. At a minimum, a day-ahead schedule of 24-hourly loads is required. Energy prices in a real time pricing market are also based upon hourly data. Most participants agreed that metered data for customers over 20 kW shall consist at a minimum of hourly demand (kW), and energy (kWh). Enron's position was that metering requirements would be determined by the filed tariffs.

The need for reactive metering would be consistent with the existing tariffs which provide that, at its sole discretion, the LDC will determine the need for reactive metering on a case by case basis to insure least cost system operations and effective cost allocations, and or compliance with any FERC requirements.

The reactive metering costs will be borne by the direct access customer. Yet to be determined are the minimum data which must be maintained and provided by the responsible MA (e.g. read dates, whether the data is actual or estimated, time stamps, adjustment flags multipliers, LDC/ESP identifiers etc.).

8. ISSUE: Metering Identifiers. As a result of direct access implementation in the restructuring of the electric industry, participants are scheduled to have access to critical customer information. This information exchange can be facilitated by the institution of common data identifiers. One such concept is the institution of common data identifiers for customers, premises, and delivery points. A universal identifier acceptable to all affected parties will provide the basis to establish an open architecture for information exchange. Key to successful implementation of universal identifiers is agreement on a set of definitions for customers, premises, and delivery points. Today, a variety of terms and definitions are in use, such as meter, account and SIC to identify customer related information. To optimize the information exchange process, the universal identifier must be non-intelligent, permanent, and simple. An example of an identifier that meets these characteristics would be a sequential 10-digit number, which could accommodate the existing LDC identifiers.

A universal identifier will provide immense benefits in the identification and consistent definition of customers, premises, and delivery points. Once a unique identifier is established, it is rather simple to consistently associate the relationship of the data entities under consideration. For example, a customer may have one or more premises. A premises may have one or more delivery points. There may be multiple accounts associated with identified customers, premises, and delivery points. The use of universal identifiers will facilitate access to energy consumption and related data on a consistent basis. Any identifier ultimately accepted must be consistent with current existing LDC identifiers. Changes to these existing identifiers could result in higher costs to the LDCs.

While there was consensus regarding the need for a universal metering identifier, no such identifier was addressed at the meetings and this issue must be resolved in the future.

9. ISSUE: Meter Data Access Rights. Access to end-use data should be available to the LDC, the ESP, and their designated metering and billing agents who require the data for operations and billing. No other party may have access to such data without specific authorization from the end-use customer. In the case where the LDC is the MA, the LDC will be required to make validated meter data available to the authorized ESP to satisfy the ESP's billing requirements. Any other authorized party will also be provided such data under similar terms and conditions. If the ESP is the MA, the ESP must provide the LDC with validated meter data to satisfy tariff billing and operational requirements. The method of compensation was not resolved.

10. ISSUE: Performance Metering Specifications and Standards. The identification and agreement on standards should be determined at a later date to insure that this critical area of agreement is adequately explored and resolved. The Subcommittee reached consensus that, as a minimum, the following standards should be adopted, where applicable:

ANSI C12.1 - Code for Electricity Metering

ANSI C12.6 - Marketing and Arrangement of Terminals for Phase Shifting Devices used in Metering

ANSI C12.7 - Watt-hour Meter Socket

ANSI C12.10 - Electromechanical Watt-hour Meters

ANSI C12.11 - Instrument Transformers for Revenue Metering, 10 kV- 350 kV (0.6-69kV NSV)

ANSI C12.13 - Electronic TOU Registers for Electricity Meters

ANSI C12.18 - Type 2 Optical Port

ANSI C12.19 - Utility Industry End Device Data Table

ANSI C12.20 - 0.2% and 0.5% Accuracy Class Meters (approved but not yet released)

ANSI C12.21 - Protocol Specification for Telephone Modem (not yet approved)

ANSI C12.22 - Meter Interface to Network Protocol Gateway (not yet approved)

ANSI C37.90 - Surge Withstand Test

ANSI 57.13 - Instrument Transformers (70 kV - 230 kV NSV)

ANSI Z1.4 - Sampling Procedures and Tables for Inspection

ANSI Z1.9 - Sampling Procedures and Tables for Inspection

EEI Electricity Metering Handbook

Electric Utilities Service Equipment Requirements Committee (EUSERC) Book NEC and Local Requirements

Although each utility presently has individualized standards for utility service, installation, maintenance and testing requirements, there was consensus that the metering agents will strive to develop common standards, where appropriate.

• Meter Accuracy

All Metering Agents must meet the existing Commission requirements for metering accuracy (+ or - 3 percent); however, a more restrictive ANSI standard may be appropriate in the future.

• Installation

All meters and installations shall meet the LDC's and ESP's safety requirements. Service and metering equipment shall meet the LDC's published electrical service requirements based on Electric Utility Service Equipment Requirements Committee (EUSERC). Meter installations may be subject to permitting and inspections by the local authority having jurisdiction for compliance with local codes and ordinances. The local authority having jurisdiction shall release all inspection clearances to the LDC. MA's must coordinate the installation of new meters and meter change-outs with the LDC and the ESP. MAs are responsible for notifying the customer, the ESP and LDC of required repairs.

• Open Architecture

A critical requirement of direct access is the communication of interval metered data to a variety of key players. It is imperative that this specification include references to the entire process of data communication including data format, storage, access rights, validation, editing, responsibilities, etc. Historically, each meter manufacturer developed their own communications protocols for interrogating and programming their own meters. This process led to the emergence of such software products as MV-90, which can communicate to multiple platforms and convert information to a common format. Considerable inefficiencies could be circumvented by migrating to standard formats such as the ANSI C12.19 Utility Industry End Device Data Tables. This specification should, at a minimum, call for adherence to this standard for metered data storage, where applicable.

Open architecture makes it possible for customers to switch energy suppliers without changing meters. The principle is to ensure that multiple ESPs can use, or read a particular meter, subject to having proper authority with proper security protection. Thus, open architecture standards are desirable. Without some level of standards, ESPs could create barriers to customer switching via proprietary metering systems. Enron and CellNet advocate the model that was adopted in the telecommunications industry and was proposed in the July 25, 1997, Meter and Data Communications Workshop Report to the California Public Utilities Commission. This model allows various telephones (cellular, PCS, traditional lines, etc) to communicate with any other type of telephone. This has created a fiercely competitive industry, which benefits customers. The proposed California model would require the MA to license their communications protocol, but not security passwords, at the meter to any market participant. APS feels that this requirement would breach the security of metered data and, at worst, incur significant transition costs to customers for reprogramming or rendering existing meters useless, thus increasingly stranded costs. The other area of open architecture should occur at the meter data management server. APS suggested that the marketplace would establish any open architecture desired or needed without regulatory intervention. The data format and communication standards for the server have been discussed at a high-level in other portions of the Areas of Agreement of this report.

11. ISSUE: Validating, Editing, Estimating, and Storage. Currently all utilities have their own set of validating, editing, and estimating (VEE) standards. Many of these standards were developed for the most part to manage simple kWh monthly meter reads and not hourly data. The Subcommittee agrees with APS' recommendation that developing common standards through a consensus process will require more time and a different group of technical experts than currently exists in the Subcommittee. Therefore, the Subcommittee recommends that agreement be reached on the need for a common set of VEE standards at this time. Enron provided the following initial list to the Subcommittee for future consideration:

• Interval Data Transformation

Standard and approved quality checks on raw meter read data will be performed. These checks include validating, estimating and/or editing consumption data to render it validated where required by market participants as defined in this section.

• Consumption data will be validated and corrected using the following approved and documented validations and algorithms.

1. Spike Check

1. High Low Average Daily Usage Check
2. Sum Check
3. Hardware Checks
4. kVarh (If collected, additional estimation rules.)

• Validation results will be stored with and at the same interval frequency as the source data.
• Estimated usage data will be identified and what percentage of estimated usage data will be allowed. The estimation technique will accompany this identification.
• Usage data will be translated to and maintained in the agreed upon MA data exchange format.
• Monthly Validating, Estimating and Editing.

• Hi/Low Usage
• Hi/Low Demand
• TOU Usage
• Zero Consumption for Active Meters
• Usage for Inactive Meters

• Meter Configuration Recommendations

1. Meter Read Dial Quantity Difference
2. Meter Read Dial Decimal Quantity Difference
3. External Meter Identification

a. Missing Usage Meter Read

b. Missing Demand Meter Read

12. ISSUE: FERC Requirements. In the Federal Energy Regulatory Commission's (FERC) Open Access rulemaking (FERC Order 888/888A), FERC held that it had 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. FERC further agreed that when transmission is sold at retail as part and parcel of a bundled delivered product called electric energy, the transaction is a sale of electric energy at retail and, therefore, the bundled transmission service is outside the authority of the FERC.

The FERC will exercise jurisdiction over all other aspects of this transaction, most notably those involving transmission and ancillary services. It is in this area of influence that the FERC has established some requirements relative to metering. The FERC has determined that any entity seeking and acquiring access to third party energy suppliers, should have the capability of determining hourly consumption for purposes of billing required services (i.e., transmission and ancillary services). If it is found that an Affected Utility's current FERC open access tariff requires modification to facilitate data access and to fully accommodate retail access, then the Arizona Corporation Commission may have to cooperate or concur with the incumbent utilities for an unbundled retail transmission tariff to the FERC.

13. ISSUE: Data Access Frequency and Timeliness. The consensus was that access to meter data should be at a minimum on a monthly basis for validated meter reads necessary for billing purposes. Such information should be made available to the electronic mailbox within 24 hours of the actual meter read date for customers who have untimed meters and within 48 hours for customers who have hourly interval meters.

15. ISSUE: Should Load Profiling Be Allowed? Load profiling is the process of estimating a customer's hourly load shape based on an appropriate sample of historical usage patterns for similarly situated customers. There was consensus that load profiling should be allowed as an economic alternative to hourly meter reading. A proposal was made that customers under 20 kW, at least initially, be permitted to use load profiling to satisfy the requirements for hourly consumption data. Such a load profiling provision should include the requirement for a statistically significant metered load sampling basis to meet scheduling and settlement requirements. The method for allocating cost responsibility to ESP's for any irreconcilable energy imbalance charges resulting from the inaccuracies introduced by load profiling remains to be determined. Ultimate implementation of hourly metering for customers under 20 kW will be determined by the experience gained with the application of load profiling as well as the economics of system-wide hourly metering implementation. The Mines and the Coalition note that the appropriate minimum level for requiring hourly metering may be in the 20-50 kW range, as has been determined in California. APS suggests that consideration should be given to equating kW to kWh to facilitate the identification of customers eligible for load profiling.

Load profiling methodologies need to be periodically reviewed by the Commission to determine whether it is appropriate to continue their use. The inaccuracies inherent in load profiling may disadvantage some customers by requiring that they pay based on a load profile that is different than their own. ACAA suggests that customers should be held harmless from any negative consequences as a result of the design and implementation of load profiling. It is essential that the load profiling methodology be reviewed and updated regularly by the LDC and the ESP's to ensure that the profile adequately reflects the usage patterns of the customer it is modeling. Ultimately, dynamic load profiling should be the goal, if load profiling continues. This would permit the ESP's to modify the load profiles of its customers based on the most current usage information and will help reduce variations between the load profile and actual usage and will reduce any misallocation of costs.

1. ISSUE: Economic Efficiency. One of the fundamental overriding objectives of competition in any industry (including the electric industry) is the attainment of greater economic efficiency. The prevailing wisdom on the subject dictates that in order to achieve this goal it is imperative that consumers receive appropriate pricing signals that accurately reflect the cost of the product they are consuming or the service they are receiving. Electric energy is a commodity which all suppliers recognize has a cost that varies depending on a number of possible factors including the nature of the fuel source for the generation, the time of year and the time of day in which it is supplied. Accordingly, the unresolved issue involves how to best ensure that consumers receive price signals consistent with their individual usage.

2. ISSUE: System Reliability. As part of the procedures associated with energy supply, third party suppliers will have to furnish energy schedules for their customers, including any that may be load-profiled. In day-ahead planning, the anticipated hourly energy usage of customers along with the resources necessary to meet that demand (plus reserves) is scheduled with the transmission system's control area operator. In a competitive market, the schedules of retail customer loads will be furnished by authorized scheduling entities, such as aggregators. These scheduling entities will be required to submit schedules in which expected hourly loads and resources are in balance and reserves are provided. It is well understood that actual loads and schedules will not match perfectly. For this reason, the control area operator is required by FERC to provide regulation and frequency response service, the cost of which is charged to customers as an ancillary service. In performing this service, the control area operator uses Automatic Generation Control (AGC) to make sure that resources exactly match load in real time, ensuring system reliability.

Some parties are concerned that load profiling will decrease the accuracy of scheduling process, thereby making day-ahead planning more difficult. Others point out that those who submit inaccurate schedules will be subject to monthly energy imbalance charges. These charges will be assessed after monthly energy usage is apportioned in accordance with the customers' respective load profiles. All parties agree that the load profiling protocol should be designed in a way that minimizes the opportunities for taking unfair advantage of the scheduling process

3. ISSUE: Proper Allocation of Costs to Customers. An additional unresolved issue with load profiling is how to best ensure that consumers are paying an appropriate amount for their individual contribution to the system peak or to the peak hours. This issue occurs because every customer in a particular class is lumped in with all others of that class and a usage pattern is deduced for the class as a whole. Energy will then be scheduled to cover the generalized estimates for the customer class's needs without any specific consideration of individual customers taking place. (Without hourly meters this is all you can do.) This method has the distinct disadvantages of (a) failing to monitor the hourly use of individual customers, many of whom may be larger users of electricity than those included in their class during the more expensive peak periods, and (b) requiring the control area operator (or the ISO) to supply, or arrange for the supply of, any additional energy that may be needed above the estimated scheduled amounts for those customers who are consuming more than anticipated by their generation suppliers without the control area operator (or the ISO) being able to specifically identify those individual customers who are the cause of the energy deficiencies. The inability of the control area operator (or ISO) to identify those individual customers who are these energy "absorbers" leads to the economically distorting effect of costs being incurred without proper assignment to the customers causing them. In the absence of hourly metering, all that can be done is to assign the additional costs over the entire class and build them into the customer charges, probably on an average basis. But this solution cuts against the grain of competition's objectives by failing to link cost responsibility to cost causation.

One way to capture as much allocable efficiency as possible is to require that all time-of-day information captured by an individual customer's meter be used in fitting his or her energy usage into the load profile. Thus, for example, a customer with a time-of-day meter would have his or her known on-peak hours placed within the on-peak portion of the load profile.

4. ISSUE: Proper Allocation of Costs to Third Party Suppliers. Another issue is that energy suppliers are not being assessed appropriate cost responsibility for any energy deficiencies that have to be made up by the control area operator (or ISO) to ensure energy deliveries to load-profiled customers. Unless all load-profiled customers are supplied by one energy company, the inability of the control area operator (or ISO) to identify specific customers responsible for unscheduled energy additions during given hours will consequently render that entity unable to specifically identify the energy supplier that should be responsible for the additional cost. Again, some form of averaging or generalized cost will have to be spread over all suppliers of that particular customer class; this will, of course, mean that some suppliers will pay more than their customers are actually responsible for and some will pay less. The issue then becomes one of finding the best possible way to ensure that suppliers pay their fair share of the cost.

VIII. BILLING AND COLLECTIONS

A. INTRODUCTION

On April 9, 1997, the first meeting was held of the Unbundled Services and Standard Offer Working Group. The objectives of the Working Group and the key issues were developed at this first meeting. At the next meeting of the Working Group on May 9, 1997, the participants began discussing the key issues. During these discussions, it became apparent that the implementation of the billing and collection issues would involve much more discussion. Thus, the participants agreed to establish a Billing and Collection (B and C) Subcommittee. Representatives from APS, ACAA, Enron, ESI, Tucson Electric Power, Trico Electric Cooperative, Citizens Utilities, Sulphur Springs Valley Electric Cooperative (SSVEC), the City of Mesa and the City of Tucson volunteered to be on the subcommittee. The Residential Utility Consumer Office was also invited to participate in the subcommittee. David Jankofsky, chairman of the Working Group, appointed John Wallace of the Commission Staff to head the Subcommittee.

B. ACTIVITIES OF THE BILLING AND COLLECTION SUBCOMMITTEE

The first meeting of the Billing and Collection (B and C) Subcommittee was held on May 28, 1997. The Subcommittee developed a scope of issues relative to billing and collection, which are required to be resolved in order to implement the Commission's Retail Electric Competition Rules. The Subcommittee's objectives were to identify, discuss, and resolve billing and collection issues for the purpose of making recommendations to the Commission for incorporation in appropriate rule making. The Subcommittee began with 41 key issues regarding billing and collection. At the August 21 meeting, these were consolidated into nine major issue categories:

• What bill options are available?
• Who is the responsible paying party?
• Who should have the authority to order a disconnect, connect or reconnect?
• What are the communications standards?
• What minimum information needs to be included on the bill?
• How does the customer switch his/her supplier?
• What consumer protection standards need to be in place, including confidentiality of billing data, etc.?
• What type of billing data needs to be stored? For how long? Who should store it?
• Whose phone numbers should be on the bill?

• Customer name and address
• Date and meter reading at the start of the billing period or number of days in the billing period
• Date and meter reading at the end of the billing period
• Billed usage and demand
• Rate Schedule number
• LDC and Billing Agent (if the ESP) telephone number(s)
• Service account number
• Amount due and due date
• Past due amount
• Adjustment factor, where applicable
• Applicable taxes
• The ACC telephone number and address
• Basic Service Charge
• Distribution Charge
• Transmission and ancillary services charges
• Generation (i.e., ESP energy charge)
• System Benefits Charge
• CTC charge
• Metering and billing charges
• Other products and service charges (if applicable)

• Customer Name and Address and other identifiers,
• Billing Period for which the bill is rendered,
• Billed Usage and Demand, if applicable, and other information necessary to determine computation of the bill,
• Amount Due, Due Date, and Past Due amount,
• Telephone numbers of the ACC, LDC and ESP.

Enron and TEP also believe that the amount of information included on residential bills should be determined by the competitive market. Enron and TEP believe if customers want more billing information, then they can call their billing agent and receive it. Some participants believe that competition will provide innovation in billing. They believe that making the requirements to include 20 items on a bill as a minimum standard is over-prescriptive and counter to the goal.

Participants also debated whether unit pricing and type of generation by percentage should be included on residential customers' bills. During Subcommittee meetings, there was consensus that such information should not be placed on the customers' bills. During the last meeting of the Unbundled Services Working Group, this recommendation was discussed in full detail and by a vote of 7 to 4 (which represented the number of organizations in attendance at the meeting) the Subcommittee's recommendation was accepted by the full Working Group.

5. ISSUE: How Does a Customer Switch His/Her Supplier? The participants reached the following consensus on this issue. Assuming the data communications interface between the LDC and ESP have been established and the metering requirements are met, a customer or its authorized agent must provide 15 days advance notification to the LDC and existing ESP of his/her intent to switch suppliers. {The participants acknowledge that the 15-day advance notification may be longer in rural service territories or in cases where weather prohibits the LDC from reading the meter within that time period. In these cases, participants agreed that the time period will be no longer than the next scheduled meter read date.} Other customer responsibilities in switching to an alternate ESP need to be established, but are generally not involved with billing. The existing billing agent must forward 12 months of billing history to the new ESP within the same 15-day period.

As mentioned previously, because of time constraints in completing the final report, the B and C Subcommittee recommends that it be directed to continue to review the billing and collection standards and consumer protection issues including slamming that have been incorporated into the Retail Electric Competition Rules and provide specific provisions to apply to the Energy Service Provider.

6. ISSUE: What Consumer Protection Standards Need to Be in Place, Including Confidentiality of Billing Data, Etc.? The participants reached the following consensus on the definition of customer specific billing data:

• kW, kWh, kVar, total billed amount and unique customer identifier which may include customer name, address, telephone no. and account no. {The Participants recognize that the items included in no. 1 are not an exact list.}
• Payment history (due dates, date of payment, etc.)
• Credit profile (employer, deposit information, etc.)

Customer specific billing data will only be released to parties with whom the customer has given authorization for the disclosed purpose. The customer authorization must be specific in relation to the three items listed above and must be written, electronic or through voice verification and must be able to be audited. Access to customer specific billing data will coincide with the contractual relationship with the customer. Unless otherwise specified by the customer, the previous twelve (12) months of customer specific billing data will be sent to the party that has a customer authorization.

For billing purposes, only item no. 1 (kW, kWh, etc.) above will be released to the customer's LDC and ESP without specific customer authorization.

Customers have a great deal of protection available to them in the new restructured environment. They have civil protection afforded them with regard to the contracts they sign which protect them against fraud, paying for services they do not receive, etc. They have the law to protect them against illegal discriminatory practices such as red-lining. The Commission's existing rules provide consumer protection. The licensing procedure or the application for a Certificate of Convenience and Necessity (CC&N) requires proof of financial viability, to reduce the potential of unscrupulous, "fly-by-night" ESPs. It also provides for disclosure of a maximum lawful rate to be charged for service under the adoption of a tariff. In addition, the customer protection and customer switching sections of this report provide further customer protection with regards to ordering disconnects, connects, and reconnects as well as switching energy suppliers.

7. ISSUE: What Type of Billing Data Needs to be Stored? For How Long? Who Should Store It? The participants reached the following consensus on these issues. Data used in determining the bill should be stored for a minimum of three (3) years. Thirteen (13) months of on-line billing data will be maintained in the agreed upon standard format. The designated billing agent shall maintain its billing data for a minimum of three years. These requirements are in addition to any federal, state or local requirements.

8. ISSUE: Whose Telephone Numbers Should Appear on the Bill? The consensus of the participants in the B and C Subcommittee was that the telephone number of the LDC, ESP and the ACC should appear on a customer's bill.

D. UNRESOLVED ISSUE

ISSUE: What Billing Options Are Available? The participants in the B and C Subcommittee identified three billing options.

Option 1: Two Separate Bills, one bill from the Electric Service Provider (ESP) and one bill from the Local Distribution Company (LDC). For the purpose of this report, the LDC provides Distribution Service as defined by Commission's Retail Electric Competition Rules.

Option 2: A combined bill from the LDC that includes charges from the ESP.

Option 3: A combined bill from the ESP that includes charges from the LDC.

There was not an agreement among participants about whether the consumer or the LDC and ESP should choose the billing options available to consumers. ENRON, PG&E Energy Services, RUCO and the Mines and the Coalition believed that it should be the customer who chooses among the three options.

APS, TRICO, Navopache and Citizens believed that the LDC and ESP should mutually agree to which of the three options are available to customers. After a determination on billing options is made by the LDC and ESP, the consumer would be able to choose among the mutually agreed upon billing options. If the LDC and ESP cannot come to agreement regarding the billing options available to customers, then the option of separate billing will be the only option available to customers. In addition, if a LDC or ESP is unwilling to provide consolidated billing and collection services, then this would limit customers' choices for billing options.

TEP and ACAA believed that during the transition period to competition, the consumer should receive a consolidated bill from the LDC in order to keep the transition to competition as simple as possible for the consumers. After the transition period, the consumer should be able to choose among the billing options.

There was also a discussion about whether a LDC could directly provide consolidated billing services or whether the LDC must form an independent affiliate to provide consolidated billing services. PG&E Energy Services and Enron's position was that the LDC must form an independent affiliate to provide consolidated billing services.

IX. CUSTOMER REQUIREMENTS

The Unbundled Services and Standard Offer Working Group also identified a series of questions/issues designed to determine roles of the various stakeholders in the process of educating customers about the emerging competitive world of electricity. It was noted that thirteen years after the divestiture of the telecommunications industry, many consumers were still unaware that the company that carried their local calls may not be the same company carrying long distance ones. And, while some education would take place as a result of the marketing efforts of the participants in the market, the Working Group members recognized the need for additional "non-advocacy" education so that consumers could better evaluate the marketing claims of the vested interests and generally make better decisions.

1. AREAS OF AGREEMENT

1. ISSUE: Telephone Number on the Bill. The first issue discussed was the Billing and Collection Subcommittee's recommendation of which telephone numbers should be included on customers' bills. This issue applies to those customers who choose to receive non-Standard Offer Service. In such instances, a new provider may be providing metering, as well as billing and collection service to a particular customer. The new provider, then, is essentially the point of contact that the customer has with the electric "world", although transmission and distribution is, in all probability, coming from a second company, and generation may be originating from a third source.

New providers would generally prefer to be the only point of contact for the customer, and, therefore, the only telephone number on the bill. In the case of a billing problem, it is clear that the new provider would be required to answer the customers' questions and resolve their problems. However, if the problem that the customer has is an outage caused, for example, by an electrical storm, the distribution company is the entity with the most current information on the cause and when power might be restored.

New providers argue that, in this scenario, it is up to them to establish systems and lines of communication with the distribution company to get enough information so that the new provider can answer customer inquiries. Indeed, the new provider is also a customer of the distribution company. The new provider should get the same good customer service as would an end-use customer. The conclusion of this reasoning is that the only telephone number that should be on the end-user's bill is that of the new provider. To the extent that the new provider does not answer questions to the customers' satisfaction, a loss of customers may occur.

Incumbent utilities argue that most customer-service calls involve outages and that they, as the "wires companies" should also be listed on the bill to ensure that end-users get the most current information available on their particular problem. Incumbent utilities also stated that they have sophisticated systems in place that provide immediate identification of customer outage areas and that capability would allow the LDC to give a more immediate and accurate response to the customer inquiry.

After much discussion, it was the consensus of the Working Group that both telephone numbers should be on the bill: that of the new provider or their representative, and the number of the distribution company. Indeed, the existing rule R14-2-210.B.2.e., which is incorporated by reference into the rules governing the transition to competition (R14-2-1613.A.) requires the telephone number of the new provider. It would be logical for a message to appear next to the telephone numbers to the effect that questions about outages should be directed to the distribution company, while all other questions should be directed to the new provider. (The Billing and Collection Subcommittee also has indicated that, pursuant to R14-2-1613.H., the number of the Corporation Commission should also be on the bill, as is reported in that chapter of this report.)

2. ISSUE: Customer Complaints. The second issue discussed derived from the first. Working Group participants desired information on the measures that would be used by the Commission's Consumer Services Section to ensure that customers received timely information in response to their complaints or inquiries. After being given such a briefing by Commission Staff (that taking and responding to complaints was the singular function of Consumer Services Section), Working Group participants felt that the existing mechanism was adequate to handle consumer complaints/inquiries, so long as Utilities Division management monitored the complaint level to ensure that the level of inquiries during the transition did not overwhelm the ability of the Staff to handle them. In addition to the Commission complaint resolution process, the Commission may require that the ESP's demonstrate a complaint resolution procedure.

3. ISSUE: Consumer Education. Deriving from this discussion, in turn, was a question regarding customer education in general. While there will be great amounts of information coming from the providers-incumbent as well as new-in the competitive market, that information will undoubtedly be heavily laced with marketing the services of a particular provider. There was a general consensus among the members of the group that the Commission had a role to play in providing a certain amount of "baseline", unbiased information that consumers could use as aids in making choices. The exact mechanism was left undeveloped, due to the time constraints on the Working Group. However, Staff is considering a mechanism similar to the Small Water Assistance Team concept in which some information is developed by Staff and made available to the public at the Commission offices in Phoenix and Tucson. Additionally, a series of "town hall"-type meetings would be held using this model to explain the principles of electric competition to attendees and to educate them on the types of issues they should analyze in making any choices offered to them. The Working Group recommended that the Commission require Staff to form a new Customer Education Working Group to develop specific recommendations on Customer Education programs.

In the context of customer education, the idea of a Commission Staff-approved bill insert was also discussed. The first question that naturally arose was the number of such bill inserts that would be required. Some participants felt that one was insufficient and that three might be a better number in order to increase the chances that customers would take the time to read the information at least once. Depending upon the precise educational mechanism, the costs could be quite high. In California, approximately $89 million is being spent on education. While there is precedent in the telephone industry for mechanisms such as this (for example, see R14-2-1401, et seq.), with mechanisms for cost recovery by the telephone companies involved (e.g. R14-2-1408), the situations are not necessarily analogous, leaving incumbents in the position of trying to recover the costs of such a program, they argue, from their remaining "captive" ratepayers, or having shareholders bear this burden.

X. ADMINISTRATIVE REQUIREMENTS

Various administrative questions were also discussed by the Working Group. Most of these dealt with the mechanisms for filing tariffs and changing existing tariffs and are generally covered by the existing statutes and regulations governing such filings.

The first administrative issue discussed by the participants in the Working Group was the tariff filing date: December 31, 1997, for both Standard Offer and Unbundled Service offerings. While some members of the group disagree with the date as matter of policy, that issue was beyond the scope of this Group. Incumbent utilities, while required to file unbundled service tariff offerings by December 31, 1997, are not technically required to file Standard Offer tariffs unless they so choose. If an incumbent does not file a Standard Offer tariff, the approved tariff currently on the file with the Commission for bundled service (essentially Standard Offer Service) would remain in effect. New providers are not required to file any tariffs by December 31. However, to offer any services (except Billing and Collection), new providers would be required to file an application for a Certificate of Convenience and Necessity, and file tariffs for the services proposed to be offered. As noted earlier in this report, any tariffs filed must, by the Rules, include supporting information. They must also be non-discriminatory. Hence, to the extent that new providers wish to enter the competitive portion of the market quickly, they would have to move through this process quickly.

Incumbent utilities expressed some concern that since they would have to file unbundled tariffs by December 31 (in all probability before new providers have entered the market), that they would be "tipping their hand" on their services offered and pricing. While that in a sense in true, it is no different than the procedure that the competitive long distance carriers have historically operated under. These tariffs may be changed at the discretion of the companies, both incumbents and new entrants alike, subject to Commission approval.

ISSUE: Pricing Flexibility. Another administrative issue that arose concerned pricing flexibility once the tariffs were in effect. The Rules do presently provide for downward pricing flexibility, if so approved by the Commission (R14-2-1606.G.3.). However, the Rules do not presently provide a mechanism for raising the rates of these services outside of a rate case.

Using the telephone rules (R14-2-1401, et seq.) as a model, one possible solution would be to allow upward pricing flexibility (of a maximum rate) outside of a rate case for a service offered in a portion of the market that has been determined by the Commission to be competitive pursuant to R14-2-1606.A. The comparable telecommunications rule, R14-2-1110, provides that Commission approval is required to raise a maximum rate for a service to be considered to be competitive, after staff analysis, but a rate case is not necessary. The Working Group did feel that the tariffs and tariff changes especially required enough flexibility to be responsive to the customers' needs. To effectuate this change, a modification to the Rules would be necessary.

XI. RECOMMENDATIONS

This section contains the recommendations that came from either the Working Group itself, or from Staff as the result of the Working Group's efforts. Recommendations are considered those items that require a change or modification to the existing Rules or that require Commission action. This Section does not include a listing of the items on which the Working Group reached consensus, since many of those items of consensus/agreement do not necessitate a rule change. Those consensus items can be found in each individual chapter of this Report, and can be found in summary form in the Executive Summary at the beginning of this Report.

In addition to the consensus items mentioned in this report, the following are the recommendations to the Commission from the Unbundled Services and Standard Offer Working Group:

System Benefits Charge

• The Working Group recommends that the Commission change the wording in R14-2-1608.A. as follows:

In addition, the Affected Utility may file for a change in the System Benefits Charge at any time. Affected Utilities shall file for a review of the System Benefits Charge every three years. The amount collected annually through the System Benefits Charge shall be sufficient to fund the Affected Utilities' present Commission-approved low income, demand side management, environmental, renewables, and nuclear power plant decommissioning programs in effect from time to time.

Solar Portfolio Standard

• The Working Group recommends that the revised objectives of the Solar Portfolio Standard, as agreed upon by the Working Group and included in this report, be incorporated into the rules to clarify the purpose and future implementation of the Standard.
• The Working Group recommends that the penalty be changed to a mechanism whereby the penalty funds are utilized to install solar electricity systems in Arizona.
• The Working Group recommends that the Solar Portfolio Standard include incentives of some type to encourage the electric service providers to take actions which will better meet the objectives of the Solar Portfolio Standard.
• The Working Group recommends that Electric Service Providers be allowed to "bank" or save up any extra (that is, above the annual portfolio requirement) solar kWh produced in a year for use in later years.
• The Working Group recommends that excess solar kWh should be tradable commodities that may be sold to other interested parties.
• The Working Group recommends that the cost of the Solar Portfolio Standard should be limited to an acceptable cost/benefit point, and a cost-reduction incentive should be provided to protect Arizona consumers from increasing solar purchases if lower-price objectives are not met. The Working Group recommends that the Commission establish a mechanism to develop the cost-impact cap and decide on a date when the costs of solar electricity is to be compared to the cost-impact cap. This "decision point" would be used by the Commission to determine if the Solar Portfolio Standard percentage should change.

Metering/Meter Reading Issues

• The Working Group recommends that the definition of metering and meter reading services be added to the Electric Competition Rules.
• The Working Group recommends that the Rules state that the internet is the preferred method for handling metered data exchange.

• The Working Group recommends that the rules say that "Any tariffs submitted for competitive unbundled services shall include information about any elements necessary for the consumer to receive full electric service. It is presumed that any contingency charges (e.g. transmission congestion charges, or energy imbalance charges) are the responsibility of the provider unless specifically stated otherwise in the tariff."
• The Working Group recommends that, for customers in the competitive environment, the telephone numbers of both the Electric Service Provider and the Local Distribution Company be included on the bill.

1. STAFF RECOMMENDATIONS

To the extend that the Unbundled Services and Standard Offer Working Group was unable to come to consensus on particular issues, the Staff has developed recommendations for Commission consideration:

Standard Offer Services

• Staff recommends that the issue of provider of last resort be addressed by the Commission at the same time as the Commission makes a determination whether competition has been substantially implemented, pursuant to R14-2-1606.

System Benefits Charge

• Staff recommends that, if the Commission decides to allow an independent SBC administrator, that the Commission relieve the affected utilities from the existing, related Commission requirements to perform such programs and provide such services. Further, Staff recommends that if the Commission decides to move to an independent SBC administration, that it be done over a reasonable transition period, to allow the affected utilities to efficiently transfer existing programs to the new, independent administrator.
• Staff recommends that, if the Commission were to opt for an independent SBC Administrator, the party making the triennial filing should change from the affected utility to the administrator, for certain of the programs mentioned.

• RECOMMENDATIONS CONCERNING FURTHER WORK

Metering/Meter Reading Issues

• The Working Group states that the Metering Subcommittee has not had enough time to accomplish its objectives and recommends that the Metering Subcommittee be allowed to continue meeting until all objectives are accomplished.
• The Working Group recommends that a workshop be held on Metering Data Exchange so that a statewide data format can be developed for exchanging data.
• The Working Group recommends that the Metering Subcommittee should develop the details on the Load Profiling methodology.
• The Working Group recommends that the Metering Subcommittee should develop the minimum metering requirements.
• The Working Group recommends that the Metering Subcommittee should determine which universal metering identifier should be used.
• The Working Group recommends that the Metering Subcommittee finalize the Performance Metering Specifications and Standards.
• The Working Group recommends that the Metering Subcommittee develop a set of Validating, Editing, and Estimating (VEE) standards.
• The Working Group recommends that the Metering Subcommittee investigate the definition and use of open architecture for metering.

Billing and Collection Issues

• The Working Group recommends that the Commission direct the Working Group to continue the efforts of the Billing and Collection Subcommittee to review the billing and collection standards and consumer protection issues.

Customer Requirements

• The Working Group recommends that the Commission require Staff to form a Customer Education Working Group to develop specific recommendations on customer education programs.