STATEMENTS OF POLICY
PENNSYLVANIA PUBLIC UTILITY COMMISSION
[52 PA. CODE CH. 69]
M-00072009
Default Service and Retail Electric Markets
[37 Pa.B. 1335]
[Saturday, March 24, 2007]The Pennsylvania Public Utility Commission, on February 8, 2007, adopted a proposed policy statement order which addresses elements of the default service regulatory framework, including default service program terms, electric generation supply procurement and competitive bid solicitation process.
Public Meeting held
February 8, 2007Commissioners Present: Wendell F. Holland, Chairperson; James H. Cawley, Vice Chairperson; Kim Pizzingrilli, statement as follows; Terrance J. Fitzpatrick, statement as follows
Default Service and Retail Electric Markets; Doc. No. M-00072009
Proposed Policy Statement By the Commission:
In December of 2004 the Commission issued a proposed rulemaking order to define the obligation of electric distribution companies (EDC) to serve retail electric customers at the conclusion of the restructuring transition periods. Rulemaking Re Electric Distribution Companies' Obligation to Serve Retail Customers at the Conclusion of the Transition Period Pursuant To 66 Pa.C.S. § 2807(e)(2), Docket No. L-00040169 (Proposed Rulemaking Order entered December 16, 2004). The Public Comment period for this rulemaking ended in April of 2006.
Over the past several years the Commission has studied developments in retail and wholesale energy markets with the objective of developing a final version of these regulations, including the integration of the requirements of the Alternative Energy Portfolio Standards Act of 2004, 73 P. S. § 1648.1, et seq. We also initiated a separate investigation in 2006 to develop policy tools to mitigate the effect of potential electricity price increases. In addition to this policy statement, today we are releasing an advance notice of final rulemaking for the default service regulations, and our findings regarding proposals for addressing electricity price mitigation.1
In reviewing the comments and considering the revisions to the proposed default service rules, the Commission recognized that there were practical limits to its regulation of large, complex energy markets. Requirements that might seem very appropriate today could be rendered obsolete by changes in markets, applicable law, or advances in technology. Accordingly, the Commission determined that some elements of the default service regulatory framework would be best addressed in the context of a policy statement that provides guidance to the industry as opposed to strict rules. A policy statement is more readily subject to change, and can provide needed flexibility to the Commission and market participants in the context of default service as energy markets continue to develop. The Commission anticipates that the initial guidelines will be applied to the first set of default service programs following the expiration of the generation rate caps, and these guidelines will be reevaluated prior to the filing of subsequent default service plans.
This policy statement, coupled with the default service regulations, and the order on electricity price mitigation, represents a comprehensive strategy for addressing retail rates in the context of expiring rate caps. We recommend that interested parties review all three documents in formulating their comments.
DISCUSSION
In the following sections we will review each element of this policy statement.
A. § 69.1801. and § 69.1802. Statements of Scope and Purpose
Sections 69.1801 and 69.1802 identify the Commission's objective for this policy statement. Given the rapid pace of change in wholesale energy markets, the Commission concludes that it would be unwise to craft a one size fits all approach at this time to every aspect of default service. These guidelines and the associated default service regulations will provide the necessary framework for default service providers (DSPs) and the Commission to manage the default service obligation.
B. § 69.1803. Definitions
For ease of reference, the Commission incorporates many of the default service regulation definitions at this section.
C. § 69.1804. Default service program terms and filing schedules
In the advance notice of final rulemaking order for default service (ANOFR), we state that we are unable to identify the optimal program duration. It may be that there is no standard program duration that is appropriate to all DSPs in all circumstances. Accordingly, we have included these guidelines recommending two year terms for all DSP programs following the initial filing. The Commission may modify this standard as markets mature.
D. § 69.1805. Electric generation supply procurement
The Commission has made the decision at this time not to follow the statewide energy procurement model used by New Jersey. While this approach is attractive to many wholesale energy suppliers, given its administrative efficiencies and manifest transparency, we have concluded that each DSP should craft an approach best suited to its own service territory. Our decision to encourage a portfolio approach with regular price adjustments also does not lend itself to the application of the New Jersey model. Finally, we are not convinced that the New Jersey procurement approach for residential customers has allowed meaningful retail competition to develop for these customers at this time.
We acknowledge that the recommendations found in this policy statement are guidelines, and not regulations. Accordingly, a DSP may propose procurement approaches that vary from those outlined in this policy statement. However, a DSP should be prepared to offer compelling evidence for taking an alternative approach. While we are giving DSPs some latitude in managing this obligation, we will be closely monitoring their performance. Should our experience lead us to conclude that too much discretion has been afforded to DSPs, we will revise the default service regulations and this policy statement accordingly.
Section 69.1805 encourages DSPs to consider a portfolio approach in managing their default service obligation. As discussed at length in the ANOFR, the Commission is cognizant of the risks associated with procuring all supply for several years or more at a single point in time. New Jersey has attempted to mitigate this risk by laddering the wholesale energy contracts used to satisfy basic generation service.
We also encourage the laddering of contracts. However, we also recommend that each DSP consider making multiple procurements over the course of a year, and to incorporate spot market purchases into their strategy. We suggest different procurement strategies for different customer classes, consistent with the level of energy knowledge, financial resources, and opportunity to shop associated with these groups.
E. § 69.1806. Alternative energy portfolio standard compliance
Many parties have asserted that the portfolio requirement of the Alternative Energy Portfolio Standards Act of 2004, 73 P. S. § 1648.1, et seq., cannot be satisfied without the use of long-term power purchase agreements between DSPs and alternative energy suppliers. Without the ability to sell electricity through a long-term contract, some project developers may not be able to acquire needed investment to build these systems.
This is a problematic issue given the requirements of Section 2807(e)(3) of the Public Utility Code, 66 Pa.C.S. § 2807(e)(3), that supply for default service customers be acquired at ''prevailing market prices.'' The alternative energy portfolio requirement, as it impacts sales of electricity to retail customers after the expiration of generation rate caps, is a component of our regulation default service.
In § 69.1806 of this proposed policy statement, the Commission observes that its default service regulations neither mandate nor prohibit long-term contracts. The term ''long-term contract'' is not readily subject to definition. A twenty to thirty year contract is certainly long-term. Some parties dispute whether a twenty to thirty year PPA can reflect prevailing market prices. We are reminded of our experience with PPAs approved by the Commission pursuant to the Public Utility Regulatory Policies Act of 1978. The rates negotiated for electricity under these PPA often diverged substantially from prevailing market prices over time. It is less clear whether contracts of shorter duration are as problematic.
F. § 69.1807. Competitive bid solicitation processes
This section includes an array of guidelines intended to improve competitive solicitation processes. In this section the Commission expresses its policy preferences on a range of issues. For example, the Commission recommends that load be procured for customer groupings (e.g., small customers vs. large customers), as opposed to slices of the DSP's overall load.
We also identify several issues that will be referred to an existing proceeding, Standardization of Request for Proposal Documents and Supplier Master Agreements in the Context of Default Service, Docket No. M-00061960, for study and policy recommendations. This includes the development of uniform bidder qualification rules, standards for confidential bid information, etc. This working group should provide recommendations on these issues, and those previously assigned, to the Commission by July 1, 2007.
G. § 69.1808. Default service cost elements
While utility rates were unbundled into transmission, distribution and generation components as part of the restructuring process, there is significant concern on the part of the Commission and others that some generation costs have been improperly allocated, or ''embedded,'' in EDC distribution rates. The Commission has not undertaken a full-fledged review of distribution rates with the goal of resolving this issue. This was in part due to the existence of rate caps and the agreements reached in the restructuring settlements. With the expiration of rate caps, there is now no obstacle to taking this issue up for consideration.
Our preference is that this issue will be addressed in the next distribution rate case for each EDC. For those EDCs who have not initiated cases by the end of 2007, the Commission reserves the right to initiate a cost allocation proceeding to resolve this issue.
H. § 69.1809. Interim price adjustments and cost reconciliation
In the ANOFR, the Commission has revised the default service regulations to require regular price adjustments and to permit a DSP to reconcile its costs and revenues. The Price-to-Compare (PTC) will change during the term of a default service program for two reasons. First, prices will be adjusted to reflect changes in incurred costs due to the use of a portfolio approach. With a portfolio approach, DSPs will be acquiring electricity through multiple procurements, some of which may be laddered contracts or spot market energy purchases. As the term covered by the laddered contract or spot market energy purchases expire, new contracts, most likely at different prices, will take effect. The PTC must be adjusted accordingly to reflect the change in costs.
Second, the PTC will need to be refined at an adjustment interval in order to reconcile default service costs and revenues. There will almost certainly be some variation between revenues received and costs incurred on a month to month basis. The Commission encourages the DSP to reconcile its rates at the regular PTC adjustment interval, similar to what a natural gas distribution company does with its gas rates. Specifically, the PTC should be recalculated to correct this divergence, and to eliminate undercollections or overcollections that have accumulated since the last PTC adjustment interval. The revised rate should be designed to eliminate these amounts by the time of the next adjustment.
This policy statement allows for interim adjustments, that is, a change in rates more frequently than at a normal adjustment interval, if there is a divergence greater than 5%. For example, a DSP may propose to revise the PTC for residential customers every quarter. In the event that incurred costs diverge from revenues by more than 5%, the DSP does not need to wait until the end of the quarter to revise its rates. It instead may file for an interim adjustment and recalculate the PTC.
I. § 69.1810. Retail rate design
The Commission finds that the PTC should reflect the cost of energy incurred, and that any disincentives to energy conservation should be eliminated from rate design. The proposed regulations expressly prohibit the PTC from being adjusted lower with increased customer usage. Accordingly, the design feature commonly known as ''declining blocks'' must be eliminated from rate design. The policy statement reaffirms this, and further provides that demand charges should be removed. We observe that Duquesne Light Company, in its most recent default service filing, is planning to discontinue all declining blocks and demand charges by 2010.
J. § 69.1811. Rate change mitigation
The Commission recognizes that some customers may experience significant rate increases when the generation rate cap expires in their EDC's service territory. This is more likely to occur in those territories where the generation rate has remained capped significantly below wholesale energy prices. The Commission finds it to be in the public interest that retail customers have reasonable opportunities to mitigate the effect of these price increases.
This policy statement recommends that DSPs give customers the option to defer paying some portion of a rate increase for a period of time in certain circumstances. Rather than adjusting a customer's PTC to the full market price all at once, the PTC would be moved incrementally over a period of several years. The customer would also gradually pay down the portion of the rate increase that was deferred. It must be acknowledged that the DSP will incur some additional expense with this type of plan, as its recovery of costs is being deferred. A customer who elects to defer some portion of the rate increase will ultimately pay more for their electricity, analogous to paying interest on a loan. Accordingly, we find that customers should have the choice to select such an option, but should not be automatically assigned to such a plan. Those who have the means and inclination to immediately pay market prices should be allowed to do so.
A DSP may propose other reasonable rate mitigation strategies for our consideration. For example, a DSP might offer customers the option to pre-pay some portion of an anticipated rate increase. Customers would be shown the current market price of energy on their monthly bill, compared to the capped rate. They would then have the option to pay the market price. This extra money would remain in the customer's account, accumulate interest, and be applied in the event that there was a significant rate increase once the rate cap expired. If the increase was less than expected, the monies could be refunded or credited to the customer's bill. This process would have the added benefit of educating consumers about market prices prior to the expiration of rate caps.
K. §§ 69.1812--69.1818. Retail Market Issues
In these sections the Commission provides guidelines on the integration of default service with the competitive retail market. The Commission has identified a number of issues where opportunities exist to enhance customer choice and facilitate the development of retail markets. Robust, effective markets are a vital element of any post-rate cap price mitigation strategy.
We are referring each issue identified in these sections to the Retail Markets Working Group for study and policy recommendations. Commission staff should convene this working group within forty five days of the issuance of a final-form policy statement. Within a reasonable period of time after convening the group, Commission staff will propose a schedule to the Commission for the development of policy recommendations. Our expectation is that the activities of this working group will be completed well before the expiration of the remaining generation rate caps.
We also find that customer education is a vital component of fostering effective retail markets. Consumer education plans that address retail choice will be required pursuant to an order we are issuing in the price mitigation proceeding at Docket M-00061957.
CONCLUSION
The Commission welcomes comments on all aspects of this proposed policy statement. It must be observed that this policy statement is closely related to the final outcome of the default service rulemaking process. Accordingly, a final policy statement will not be promulgated for publication in the Pennsylvania Bulletin until the Commission has obtained final approval of the default service regulations. Should the Independent Regulatory Review Commission or other entity require changes to the final-form version of the rule, this policy statement may need to be revised for consistency.
Therefore,
It Is Ordered That:
1. The proposed Statement of Policy in §§ 69.1801--69.1817 as set forth in Annex A, is issued for comment.
2. The Secretary shall submit this order and Annex A to the Governor's Budget Office for review of fiscal impact.
3. The Secretary shall certify this order and Annex A and deposit them with the Legislative Reference Bureau for publication in the Pennsylvania Bulletin.
4. Interested persons may submit, by March 2, 2007, an original and 15 copies of written comments to the Office of the Secretary, Pennsylvania Public Utility Commission, P. O. Box 3265, Harrisburg, PA 17105-3265. Reply comments will be submitted by March 23, 2007. To facilitate the timely posting of comments to the Commission's public internet domain, comments should also be submitted by e-mail to Shane Rooney, srooney@state. pa.us. Attachments may not exceed 3 megabytes.
5. A copy of this order shall be posted on the Commission's public internet domain and served on the Office of Consumer Advocate and Office of Small Business Advocate.
6. The contact person for this matter is Shane Rooney, (717) 787-3464, srooney@state.pa.us.
7. Commission staff convene the Retail Markets Working Group within 60 days of the issuance of a Final Form Policy Statement, consistent with the instructions given in this order.
JAMES J. MCNULTY,
SecretaryFiscal Note: 57-254. No fiscal impact; (8) recommends adoption.
Statement of Commissioner Kim Pizzingrilli Public Meeting
February 8, 2007
Electric Distribution Companies' Obligation to Serve Retail Customers at the Conclusion of the Transition Period Pursuant to 66 Pa.C.S. § 2807(e)(2); FEB-2007-L-0009*; Doc. No. L-00040169
Default Service and Retail Electric Markets Proposed Policy Statement; FEB-2007-L-0010*; Doc.No. M-00072009 Today, we issue an Advance Notice of Final Rulemaking Order (ANOFR) with an accompanying Policy Statement regarding electric distribution companies' obligation to serve retail customers at the conclusion of the transition period pursuant to Section 2807(e)(2) of the Electricity Generation Customer Choice and Competition Act (Competition Act).2
The Commission is very cognizant of how important its Default Service regulations are in the transition process to a competitive market. We have proceeded in formulating the regulations and Policy Statement in a deliberative fashion studying the experiences of other jurisdictions and taking into account stakeholder comments. I would like to thank all those who have shared their thoughts and expertise in comments filed in this proceeding.
Since the passage of the Competition Act, we have learned that the transition to market-based pricing is an evolving process. For this reason, we have chosen to issue a Policy Statement to accompany the Default Service advanced notice of final regulations. I believe that the guidance of a Policy Statement and not the mandate of a regulation is the best way to manage this process going forward allowing both the Commission and stakeholders a greater amount of flexibility as electricity markets develop. The Policy Statement announces to the public the course which the Commission intends to follow and serves to provide supplemental guidance on the fundamental provisions found in the regulations.
I also support the use of an ANOFR. These are complex issues that will have a direct impact on retail electricity prices across the Commonwealth. Therefore, the Commission would like to receive comments on the modifications made from the proposed version before they are finalized and sent to the Senate Consumer Protection and Professional Licensure Committee, the House Consumer Affairs Committee and the Independent Regulatory Review Commission for review.
Finally, I would like to thank Commission staff, particularly Shane Rooney from the Law Bureau, for the countless hours spent reviewing comments and drafting regulations.
Statement of Commissioner Terrance J. Fitzpatrick Public Meeting
February 8, 2007
Default Service and Retail Electric Markets; FEB-2007-L-10*; M-00072009 This matter involves a proposed policy statement regarding default service and retail electric markets. The policy statement is a companion document to the rulemaking regarding default service (Docket No. L-00040169) that we are also voting upon today. Both items will be issued for comment and made final later this year.
I support the approach the Commission is taking in dividing the issues regarding default service between regulations and a statement of policy. A policy statement is a more flexible tool-t is not legally binding, and it is not subject to the procedural requirements that apply to regulations. It will allow the Commission to change its policies over time as the Commission gains more experience, and as circumstances change.3 In particular, it will allow us to recognize that the default service programs filed to take effect immediately after 2010, when the generation rate caps expire for most utilities, raise a unique set of issues because of the potential for steep price increases as customers pay market-based generation prices for the first time. The policies that we apply for the first two to three years after expiration of the caps should not be the same policies that we apply to later programs. Specifically, I expect that the Commission's policies will be aimed at developing more robust retail competition over time.
Second, while I will review carefully the comments that are filed on this issue, I am inclined at the outset to support the default service purchasing strategy reflected in this policy statement. This policy encourages utilities to purchase a varied supply of energy products at different points in time, and to make timely adjustments in their retail prices for generation supply. By doing so, the supply portfolio of the utility, and the retail price for this supply, will stay reasonably in touch with changes in wholesale market conditions. At the same time, the diversity of the supply portfolio should hedge against the risk of sudden, dramatic changes in wholesale prices. This approach will allow the Commission to fulfill its duty under the Competition Act4 to establish effective retail competition, but to do so in a gradual, deliberate manner that recognizes the difficulty customers may face in making the shift from capped generation prices to market-based prices.
The Competition Act requires the Commission to encourage actual, effective retail competition5, although the exact speed and manner of reaching that goal is within the discretion of the Commission. The bedrock policy of the Act is that ''[c]ompetitive market forces are more effective than economic regulation in controlling the cost of generating electricity.'' 66 Pa. C.S. § 2802 (5). Accordingly, it is the Commission's duty to foster a truly competitive retail market, rather than to implement policies that will encourage customers to remain on the regulated default service offering, contrary to the purpose of the Act. In a nutshell, the Commission may not implement a statute entitled ''The Electricity Generation Customer Choice and Competition Act'' with an attitude of indifference as to whether competition and customer choice actually result.
I am looking forward to reading the comments on this proposed policy statement, and to taking final action in this matter in a few months.
Annex A
TITLE 52. PUBLIC UTILITIES
PART I. PUBLIC UTILITY COMMISSION
Subpart C. FIXED SERVICE UTILITIES
CHAPTER 69. GENERAL ORDERS, POLICY STATEMENTS AND GUIDELINES ON FIXED UTILITIES
DEFAULT SERVICE AND RETAIL ELECTRIC MARKETS (Editor's Note: This statement of policy refers to regulations that were proposed at 35 Pa.B. 1421 (February 26, 2005) (Fiscal Note #57-237). The regulations have not yet been adopted by the Commission.)
(Editor's Note: The following text is new. It has been printed in regular type to enhance readability.)
§ 69.1801. Statement of scope.
Sections 69.1802--69.1817 provide guidelines to default service providers regarding the acquisition of electric generation supply, the recovery of associated costs and the integration of default service with competitive retail electric markets.
§ 69.1802. Statement of purpose.
(a) The Commission has proposed regulations governing the default service obligation in §§ 54.181--54.189 (relating to default service), as required by 66 Pa.C.S. § 2807(e) (relating to duties of electric distribution companies). The regulations address the elements of a default service regulatory framework. The goal of default service regulations is to bring competitive market discipline to historically regulated markets. This can be accomplished by structuring default service in a way that encourages the entry of new retail and wholesale suppliers. Greater diversity of suppliers will benefit ratepayers and this Commonwealth. However, the regulations are not designed to resolve every possible issue relating to the acquisition of electric generation supply, the recovery of reasonable costs, the conditions of service and the relationship with the competitive retail market.
(b) The Commission is very cognizant of the practical limits of regulating large, complex markets. Changes in Federal or State law, improvements in technology and developments in wholesale energy markets may render obsolete an all-inclusive regulatory approach to this Commonwealth's retail electric market.
(c) The Commission has devised an approach that will allow this Commonwealth to adapt to changes in energy markets and the regulatory environment. The regulations which will be codified in Chapter 54 (relating to electricity generation customer choice) will serve as a general framework for default service and provide an appropriate measure of regulatory certainty for ratepayers and market participants. This section and §§ 69.1801 and 69.1803--69.1817 will provide guidelines on those matters when a degree of flexibility is required to respond effectively to regulatory and market challenges. The Commission anticipates that the initial guidelines will be applied to the first set of default service plans following expiration of the generation rate caps, and that the guidelines will be reevaluated prior to the filing of subsequent default service plans.
§ 69.1803. Definitions.
The following words and terms, when used in this section and §§ 69.1801, 69.1802 and 69.1804--69.1817, have the following meanings, unless the context clearly indicates otherwise:
Alternative energy portfolio standards--A requirement that a certain percentage of electric energy sold to retail customers in this Commonwealth by EDCs and EGSs be derived from alternative energy sources, as defined in the Alternative Energy Portfolio Standards Act (73 P. S. §§ 1648.1--1648.8).
Competitive bid solicitation process--A fair, transparent and nondiscriminatory process by which a DSP awards contracts for electric generation supply to qualified suppliers who submit the lowest bids.
DSP--Default service provider--The incumbent EDC within a certificated service territory or a Commission approved alternative default service provider.
Default service--
(i) Electric generation supply service provided by a DSP to a retail electric customer who is not receiving generation service from an EGS.
(ii) Electric generation supply service provided pursuant to a Commission approved default service plan.
Default service implementation plan--The schedule of competitive bid solicitations and spot market purchases, technical requirements and related forms and agreements.
Default service procurement plan--The electric generation supply acquisition strategy the DSP will utilize in satisfying its default service obligations, including the manner of compliance with the alternative energy portfolio standards requirement.
Default service program--A filing submitted to the Commission by the DSP that identifies a procurement plan, an implementation plan, a rate design to recover all reasonable costs and all other elements identified in § 54.185 (relating to default service implementation plans and terms of service).
EDC--Electric distribution company--The term has the same meaning as defined in 66 Pa.C.S. § 2803 (relating to definitions).
EGS--Electric generation supplier--The term has the same meaning as defined in 66 Pa.C.S. § 2803.
Maximum registered peak load--The highest level of demand for a particular customer, based on the PJM Interconnection, LLC, peak load contribution standard, or its equivalent, and as may be further defined by the EDC tariff in a particular service territory.
PTC--Price-to-compare--The rate charged to a retail electric customer by the DSP for default service.
Prevailing market prices--Prices that are available in the wholesale market at particular points in time for electric generation supply.
RTO--Regional transmission organization--A Federal Energy Regulatory Commission (FERC)-approved regional transmission organization.
Retail customer or retail electric customer--The terms have the same meaning as defined in 66 Pa.C.S. § 2803.
Spot market energy purchase--The purchase of an electric generation supply product in a FERC-approved real time or day ahead energy market.
§ 69.1804. Default service program terms and filing schedules.
The default service regulations provide for a standard initial program term of 2 to 3 years. Initial programs may vary from this standard to comply with the applicable regional transmission organization planning year. Subsequent programs should be for 2 years, unless otherwise directed by the Commission. The Commission will monitor developments in wholesale or retail markets and revisit this issue as appropriate. The Commission may revise the duration of the standard program term and program filing schedules based on market developments.
§ 69.1805. Electric generation supply procurement.
A proposed procurement plan should balance the goals of allowing the development of a competitive retail supply market and also include a prudent mix of arrangements to minimize the risk of over-reliance on any particular source. In developing a proposed procurement plan, a DSP should consider including a prudent mix of supply-side and demand-side resources such as long-term, short-term, staggered-term and spot market purchases to minimize the risk of contracting for supply at times of peak prices. Long-term contracts should only be used when necessary and required for DSP compliance with alternative energy requirements, and should be restricted to covering a relatively small portion of the default service load. An over reliance on long-term contracts would mute demand response, create the potential for future default service customers to bear future above market costs, and limit operational flexibility for DSPs to manage their default service supply. The plan should be tailored to the following customer groupings, but DSPs may propose alternative divisions of customers by registered peak load to preserve existing customer classes.
(1) Residential customers and nonresidential customers with less than 25 kW in maximum registered peak load. Initially, the DSP should acquire electric generation supply for these customers using a mix of resources as described in the introductory paragraph to this section. Consideration should be given to procuring most fixed-term supply through full requirements contracts of 1 to 3 years in duration. Contracts should be laddered to minimize risk, with a minimum of two competitive bid solicitations a year to further reduce the risk of acquisition at a time of peak prices. In subsequent programs, the percentage of supply acquired through shorter duration full requirements contracts and spot market purchases should be gradually increased, depending on developments in retail and wholesale energy markets.
(2) Nonresidential customers with 25--500 kW in maximum registered peak load. The DSP should acquire electric generation supply for these customers using a mix of resources as described in the introductory paragraph to this section. Fixed-term contracts should be 1 year in length and may be laddered to minimize risk, with a minimum of two competitive bid solicitations a year to further reduce the risk of acquisition at a time of peak prices. In subsequent programs, the percentage of supply acquired through shorter duration purchases and spot market purchases should gradually be increased, depending on developments in retail and wholesale energy markets.
(3) Nonresidential customers with greater than 500 kW in maximum registered peak load. Hourly priced or monthly-priced service should be available to these customers. The DSP may propose a fixed-price option for the Commission's consideration.
§ 69.1806. Alternative energy portfolio standard compliance.
In procuring electric generation supply for default service customers, the DSP shall comply with the Alternative Energy Portfolio Standards Act (73 P. S. §§ 1648.1--1648.8). The Commission's default service regulations neither prohibit nor mandate the use of long-term contracts to satisfy the alternative energy portfolio standards obligation. In satisfying this obligation, a DSP's procurement strategy should reflect the incurrence of reasonable costs.
§ 69.1807. Competitive bid solicitation processes.
The following guidelines will apply to competitive bid solicitation processes:
(1) DSPs should use standardized request for proposal documents and supplier master agreements approved by the Commission for use in the default service procurements. The Commission will review these documents and agreements on a regular basis and revise them when appropriate after consultation with stakeholders.
(2) The public interest would be served by the adoption of uniform criteria and processes for bidder qualification.
(3) Competitive bid solicitations should be structured along customer classes, consistent with the groupings identified in § 69.1804 (relating to default service program terms and filing schedules). Bids should be solicited for tranches of load within each customer class. Slice of system bid designs should not be utilized.
(4) The Commission finds that a clearly optimal bid solicitation model does not exist at the current stage of wholesale market development. DSPs may utilize various competitive bid solicitation approaches, including request for proposals that result in the submission of sealed bids and real time auctions in which energy suppliers compete with each other for tranches of customer load.
(5) DSPs are encouraged to coordinate their competitive bidding solicitation schedules to minimize conflicts that might negatively affect the ability of suppliers to participate in multiple procurements. DSPs with loads of greater than 50 megawatts should avoid scheduling prebid conferences, auctions, and the like, on the same day as other DSPs with loads greater than 50 megawatts.
(6) The Commission's objective is to review the results of competitive bidding processes in a manner sensitive to market dynamics but that also allows it to discharge its statutory obligations. The Commission recognizes that bid prices may be negatively affected by the length of time taken for Commission review. In the default service regulations, the Commission has reserved a period of 1 business day to review the results of competitive procurements. As retail and wholesale markets mature, and as other appropriate safeguards become available, the Commission may elect to reduce the amount of time it uses to review bidding results.
(7) The public interest would be served by the adoption of uniform rules for the confidentiality of competitive solicitation information. Supplier participation, bid prices and retail rates may be impacted by protecting certain information, including, the identity of winning and losing bidders, the number of bids submitted, bid prices, the allocation of load among winning bidders, and the like. At the same time, the Commission recognizes that there is a legitimate public interest in knowing some of this information when there is no possibility of any prejudice to ratepayer interests.
(8) The competitive bid solicitation process will be monitored by an independent evaluator. The Commission may direct that this evaluator administer competitive bid solicitations to ensure the independence of the process. This independent party will be selected by the DSP in consultation with the Commission. The DSP may not have an ownership interest in the evaluator, and vice versa, and the DSP should disclose any potential conflicts of interest on the part of the evaluator during this consultation process. The Commission will review conflicts of interest and may disqualify an evaluator in order to ensure the independence of the position. The evaluator should have an expertise in the analysis of wholesale energy markets, including methods of energy procurement. The evaluator should monitor compliance with Commission orders relating to a default service program, confidentiality agreements, and other directives. The evaluator should report all information it obtains to the Commission.
§ 69.1808. Default service cost elements.
(a) The PTC should be designed to recover all generation, transmission related and other related costs of default service. These cost elements include:
(1) Wholesale energy, capacity, ancillary, congestion, applicable RTO or ISO administrative and transmission costs.
(2) Supply management costs, including supply bidding, contracting, hedging, risk management costs, any scheduling and forecasting services provided exclusively for default service by the EDC and applicable administrative and general expenses related to these activities.
(3) Administrative costs, including billing, collection, education, regulatory, litigation, tariff filings, working capital, information system and associated administrative and general expenses related to default service.
(4) Applicable taxes, excluding sales tax.
(5) Costs for alternative energy portfolio standard compliance.
(b) EDC rates should be scrutinized for any generation related costs that remain embedded in distribution rates. This review should occur no later than the next distribution rate case for each EDC filed after _____ (Editor's Note: The blank refers to the effective date of adoption of this statement of policy.). The Commission may initiate a cost allocation case for an EDC on its own motion if a case is not initiated by December 31, 2007. Changes to rates resulting from the examination would take effect after the expiration of Commission-approved rate caps.
§ 69.1809. Interim price adjustments and cost reconciliation.
(a) Consistent with the default service regulations, the PTC will be adjusted on a regular basis to reflect changes in and ensure the recovery of reasonable costs resulting from changes in wholesale energy prices or other costs. For example, the PTC will be adjusted at least every quarter for residential customers and as frequently as every month for large business customers. This PTC adjustment may be driven by changes in spot market prices, the use of laddered contracts, the use of seasonal rate design, and the like.
(b) The public interest may be served if default service costs and the revenues received through default service rates are reconciled as part of the PTC adjustment process. Reconciliation would ensure that DSPs fully recover their actual, incurred costs without requiring customers to pay more than is required. The PTC adjustment will therefore also reflect changes required due to the reconciliation of costs and revenues. Reconciliation proposals should result in a PTC adjustment that will resolve cumulative under or over collections by the time of the next PTC adjustment interval.
(c) It may be in the public interest to reconcile default service costs more frequently than at each PTC adjustment interval. The DSP should propose interim reconciliation prior to the next subsequent PTC adjustment interval when current monthly revenues have diverged from current monthly costs, plus any cumulative over/under recoveries, by greater than 5% since the last rate adjustment. When the divergence is less than 5%, the DSP has the discretion to propose interim reconciliation prior to the next PTC adjustment interval. Interim reconciliation proposals should result in a PTC adjustment that will resolve cumulative under or over collections by the time of the next PTC adjustment interval.
§ 69.1810. Retail rate design.
Retail rates should be designed to reflect the actual, incurred cost of energy and therefore encourage energy conservation. The PTC should not incorporate declining blocks, demand charges or similar elements. The PTC for a particular customer class may be converted to a time of use design if the Commission finds it to be in the public interest.
§ 69.1811. Rate change mitigation.
(a) The following provision should apply when a DSP's total retail rate rises by more than 25% following the expiration of a generation rate cap due to wholesale energy prices. If DSPs should offer all residential and small business customers of up to 25 kW in maximum registered peak load the opportunity to prepay or defer some portion of the rate increase for as long as 3 years. These mitigation options should be included in the default service program filed for the period that begins with the expiration of the Commission-approved generation rate cap. Customers may not be assigned to a rate increase prepay or deferral program without their affirmative consent. DSPs would be able to fully recover the reasonable carrying costs associated with a rate increase deferral program, including associated administrative costs.
(b) DSPs may propose other reasonable rate mitigation strategies that would reflect the incurrence of reasonable costs.
§ 69.1812. Information and data access.
The public interest would be served by common standards and processes for access to retail electric customer information and data. This includes customer names and addresses, customer rate schedule and profile information, historical billing data and real time metered data. Retail choice, demand side response and energy conservation initiatives can be facilitated if EGSs, curtailment service providers, and other appropriate parties can obtain this information and data under reasonable terms and conditions common to all service territories, with due consideration given to customer privacy.
§ 69.1813. Rate ready billing.
The public interest would be served by the consideration of the availability of rate ready billing in each service territory.
§ 69.1814. Purchase of receivables.
The public interest would be served by the consideration of an EGS receivables purchase program in each service territory.
§ 69.1815. Customer referral program.
The public interest would be served by consideration of customer referral programs in which retail customers are referred to EGSs.
§ 69.1816. Supplier tariffs.
The public interest would be served by the adoption of supplier tariffs that are uniform as to both form and content. Uniform supplier tariffs may facilitate the participation of EGSs in the retail market of this Commonwealth and reduce the potential for mistake or misunderstandings between EGSs and EDCs.
§ 69.1817. Retail choice ombudsman.
The public interest would be served by the designation of an employee as a retail choice ombudsman at each EDC and the Commission. The ombudsman would be responsible for responding to questions from EGSs, monitoring competitive market complaints and facilitate informal dispute resolution between the DSP and EGSs.
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1 The Commission looks forward to working with the Governor and the Pennsylvania General Assembly to implement any new default service requirements that may result from legislation related to the ''Energy Independence Strategy'' announced by Governor Rendell on February 1, 2007.
2 66 Pa.C.S. §§ 2801--2812.
3 The New York Public Service Commission has developed its retail competition policies through policy statements, and I believe that this approach has been successful. See, Statement of Policy on Further Steps Toward Competition in Retail Energy Markets, Case 00-M-0504, N.Y. Public Service Com. (August 25, 2004).
4 Formally entitled the Electricity Generation Customer Choice and Competition Act, Act 138 of 1996, 66 Pa. C.S. § 2801 et seq.
5 Some parties have suggested in comments in the default service rulemaking that the Act was designed to encourage wholesale competition rather than retail competition. This is an attempt to rewrite both history and the purpose of the Act. Wholesale competition is subject to federal, not state, jurisdiction. Moreover, the language of the Act itself supports the notion that the primary innovation in the Act was giving customers the right to ''direct access to a competitive market for the generation and sale or purchase of electricity.'' 66 Pa.C.S. § 2802 (13) (emphasis added). The term ''direct access'' is a description of retail competition, whereas wholesale competition, by itself, provides only ''indirect access'' to a competitive market because the customer must purchase electricity from its electric utility.
[Pa.B. Doc. No. 07-501. Filed for public inspection March 23, 2007, 9:00 a.m.]
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