STATEMENTS OF POLICY
Title 52--PUBLIC UTILITIES
PENNSYLVANIA PUBLIC UTILITY COMMISSION
[52 PA. CODE CH. 69]
[M-00072009]
Default Service and Retail Electric Markets
[37 Pa.B. 5019]
[Saturday, September 15, 2007]The Pennsylvania Public Utility Commission, on May 10, 2007, adopted a final statement of policy 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
May 10, 2007Commissioners Present: Wendell F. Holland, Chairperson; James H. Cawley, Vice Chairperson; Kim Pizzingrilli; Terrance J. Fitzpatrick
Default Service and Retail Electric Markets; Doc. No. M-00072009
Final Policy Statement By the Commission:
On February, 8, 2007, the Commission issued a proposed version of this statement of policy and solicited public comments. See 37 Pa.B. 1335 (March 24, 2007). The Commission has completed its review of the comments and issues this final statement of policy. This statement of policy is being issued in conjunction with final form regulations on default service and a final order identifying price mitigation strategies.1
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 the proposed rulemaking ended in April 2006. The Commission issued an advance notice of final rulemaking (ANOFR) on February 8, 2007. See 37 Pa.B. 1126 (March 10, 2007).
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 statement of policy, we are issuing a final form rulemaking order for default service regulations, and our findings regarding proposals for addressing electricity price mitigation.
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 statement of policy that provides guidance to the industry as opposed to strict rules. A statement of policy 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 statement of policy, 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 and still developing retail and wholesale energy markets.
Comments and reply comments to the proposed statement of policy were filed at this docket by Allegheny Energy (Allegheny), Citizens for Pennsylvania's Future (PennFuture), Constellation Energy (Constellation), Citizens Electric Company (Citizens), Consolidated Edison Solutions (Con Edison), Direct Energy, LLC (Direct), Dominion Retail, Inc. (Dominion), Duquesne Light Company (Duquesne), the Economic Growth through Competitive Energy Markets Coalition, the Energy Association of Pennsylvania (Energy Association), FirstEnergy Operating Companies2 (FirstEnergy Companies), the Hess Corporation, the Industrial Energy Consumers of Pennsylvania, et al.3 (IECPA), Morgan Stanley Capital Group, Inc. (Morgan Stanley), the National Energy Marketers Association (NEM), the Office of Consumer Advocate (OCA), the Office of Small Business Advocate (OSBA), PECO Energy Company (PECO), PPL Electric Utilities Corporation (PPL), PPM Energy (PPM), PSEG Energy Resources & Trade LLC (PSEG ERT), PV Now, Reliant Energy, Inc. (Reliant), Richards Energy Group, Inc., the Retail Energy Supply Association (RESA), Strategic Energy, LLC (Strategic), UGI Utilities, Inc.--Electric Division (UGI), U.S. Steel Corporation, (US Steel), and the Wellsboro Electric Company (Wellsboro). All comments are available on the Commission's public internet domain.
DISCUSSION
In the following sections we will review each element of this statement of policy.
A. § 69.1801. and § 69.1802. Statements of Scope and Purpose
Sections 69.1801 and 69.1802 identify the Commission's objective for this statement of policy. 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.
In response to comments from PPL and the Energy Association to the ANOFR and Proposed Statement of Policy, the definitions of ''default service provider'' and ''default service'' have been revised. ''Default service provider'' has been changed to be consistent with the version found in the default service regulations and the definition of ''default service'' has been simplified.
C. § 69.1804. Default service program terms and filing schedules
In the rulemaking order for default service, we state that we are unable to identify the optimal program duration. There may be no standard program duration that is appropriate to all DSPs in all circumstances. Accordingly, we recommend 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 mandate 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, within the framework provided herein. Also, our decision to encourage a portfolio approach with regular price adjustments does not readily 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 resulted in the lowest prices attainable, produced meaningful market price signals, or allowed significant retail competition to develop for these customers at this time. However, as discussed in the default service regulations, the Commission will consider multi-territory procurement processes proposed by DSPs. However, such multi-territory procurements must incorporate the other aspects of this regulatory framework, including the regular adjustment of rates, flat rate design, etc.
We acknowledge that the recommendations found in this statement of policy are guidelines, and not regulations. Accordingly, a DSP may propose procurement approaches that vary from those outlined in this statement of policy. 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 statement of policy 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--1648.8) cannot be satisfied without the use of long-term power purchase agreements (PPA) 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 statement of policy, 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 at a date to be determined by the Commission.
PSEG ERT recommended that the Commission consider the use of mechanisms that track and adjust default service rates in response to increases in transmission rates. PSEG ERT notes that if wholesale suppliers are at risk for increases in transmission rates, they will include a risk premium in their competitive bids. The incorporation of a mechanism in a supplier master agreement (SMA) that allows these costs to be readily passed through may result in more competitive bids. PSEG ERT states that such a mechanism is used in the New Jersey Basic Generation Service SMA. We agree that this idea is worthy of further study, and have added § 69.1807(9) to address it.
In response to a comment by Constellation, we have revised this section to clarify that while the standard SMAs will be revised, this will only be done on a going forward basis. Changes made to the Commission approved SMA language will not be applied retroactively to existing contracts.
Several parties provided comments in response to the ANOFR or the proposed statement of policy regarding the public availability of information pertaining to winning bids. The OSBA and OCA in particular wished to clarify their access to this information. The Commission is reluctant to issue a uniform rule at this time without the benefit of a working group recommendation. We will work with the OCA and OSBA to responsibly address specific requests for data until a final policy is developed and approved.
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 coming expiration of the remaining 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. We acknowledge that adjustments to rates will be deferred until the expiration of the EDCs' effective rate caps.
In response to a comment from IECPA, we are revising this section to provide that congestion costs should generally be reflected in the fixed price bids submitted by wholesale energy suppliers. Accordingly, we would not expect congestion costs to be reconciled with regard to any fixed-price default service supply contracts.
In general, we are open to the concept of addressing the allocation of costs between generation and distribution rates through a collaborative process. We further agree that cost allocation should reflect the level of service, or lack of service, provided to default service and non-default service customers.
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. Default service rates, which customers will more clearly understand through the use of a 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 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 statement of policy 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 4%. 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 4%, 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.
In response to a comment from Constellation, we wish to clarify that the default service rate, and correspondingly the PTC, should be adjusted prospectively based on changes in the forecasted price of spot market supply products. The PTC should not be adjusted merely to reflect changes in the composition of a DSPs portfolio of energy products. However, the Commission will not be adjusting the suppliers' winning bid prices in response to changes in wholesale energy markets.
We have also adjusted the threshold for interim reconciliation from 5% to 4% in response to the comments to the proposed statement of policy.
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 final 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 default service rate design. The statement of policy 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. Consistent with the final rulemaking order, we note that generation demand charges may be proposed for large commercial and industrial customers if the charges and rate determinants are reasonably related to the wholesale energy cost of providing default service.
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 statement of policy 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, plus 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.
In response to a comment from PPL, we have clarified this section to state that the rate mitigation calculation should be performed on a customer class basis, and not a system-wide basis. A prepay or deferral option should be offered to those customer classes whose total bill increase exceeds 25%.
We also agree with the comments of Con Edison and others that any mitigation strategy be competitively neutral, and appreciate the examples of mitigation proposals they and other parties recommend. Section 69.1811 has been drafted in a way to give the Commission and companies some discretion in crafting reasonable mitigation plans.
We also recognize the challenges presented by rate increase deferrals, including the fact that customers ultimately pay more due to carrying charges. Accordingly, we emphasize that customers must affirmatively select such options to be enrolled. We would expect that customers would have to contact their DSP by phone or electronic mail, or sign and return some written authorization to the DSP, to enroll in such a program.
In response to a comment of Citizens and Wellsboro, we confirm that this provision does not apply to EDCs whose generation rate cap has already expired. These customers are already paying market based rates.
K. §§ 69.1812--69.1817. 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 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 45 days of the publication of this final statement of policy in the Pennsylvania Bulletin. 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.
Section 69.1812 has been edited at the recommendation of the OCA to emphasize that proper consideration be given to protecting private or sensitive customers information.
In response to a comment by RESA and Hess to the proposed statement of policy, we are amending § 69.1813, to require consideration of ''bill ready'' billing in addition to rate ready billing in all DSP service territories.
As a general response to the comments to these provisions, the Commission will consider the costs of implementing these policies. We believe that these policies, if properly designed, can serve the public interest. However we recognize that it may not be in the public interest to adopt all of these policies in all EDC service territories.
Finally, we will be monitoring the implementation of the purchase of receivables program in the Duquesne territory. As the OCA noted, this program was adopted in lieu of fully and finally addressing the issue of embedded generation costs in distribution rates. As an interim step in responding to § 69.1808, other EDCs may wish to consider proposing similar programs for Commission review and approval.
CONCLUSION
The Commission will closely monitor the implementation of this statement of policy and the associated default service regulations by DSPs. The statement of policy will be revised based on experience gained from future proceedings. Over time, we may find it appropriate to move some elements of this statement of policy to the default service regulations.
Unlike the default service regulations, this statement of policy does not require additional regulatory approvals to become effective. However, we will delay publication of this statement of policy in the Pennsylvania Bulletin until the default service regulations have been approved by Pennsylvania General Assembly, the Independent Regulatory Review Commission and the Pennsylvania Attorney General. Should these agencies require amendments to the regulations, this statement of policy may need to be revised. Accordingly, this statement of policy will not be published and take effect until after the default service regulations have received all regulatory approvals; Therefore,
It Is Ordered That:
1. Title 52 of the Pennsylvania Code is amended by adding a statement of policy in §§ 69.1801--69.1817 to read as set forth in Annex A.
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. This order and Annex A will be deposited with the Legislative Reference Bureau for publication in the Pennsylvania Bulletin after the regulations promulgated at Docket L-00040169 have obtained all regulatory approvals.
4. This statement of policy shall be come effective upon publication in the Pennsylvania Bulletin.
5. Alternative formats of this document are available to persons with disabilities and may be obtained by contacting Sherri DelBiondo, Regulatory Coordinator, (717) 772-4597.
6. The contact person for this matter is Shane Rooney, (717) 787-2871, srooney@state.pa.us.
7. Commission staff will convene the Retail Markets Working Group by October 30, 2007, consistent with the instructions given in this order.
JAMES J. MCNULTY,
SecretaryFiscal Note: Fiscal Note 48-254 remains valid for the final adoption of the subject regulations.
(Editor's Note: This statement of policy refers to the final-form rulemaking published at 37 Pa.B. 4996 (September 15, 2007) (Fiscal Note #57-237).)
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 § 69.1801. 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. Purpose.
(a) The Commission has adopted 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 the duties of electric distribution companies). The regulations address the elements of a default service regulatory framework. The goal of the 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 the Commonwealth. However, those rules 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 any 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 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 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 supplier of electric generation service.
Default service--Electric generation supply service provided pursuant to a default service program to a retail electric customer not receiving service from an EGS.
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 programs and periods 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--A line item that appears on a retail customer's monthly bill for default service. The PTC is equal to the sum of all unbundled generation and transmission related charges to a default service customer for that month of 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--These 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 RTO 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 including a prudent mix of arrangements to minimize the risk of over-reliance on any energy products at a particular point in time. 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 or block contracts of 1 to 3 years in duration. Contracts should be laddered to minimize risk, in which a portion of the portfolio changes at least annually, 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. Revisions to these documents will not be applied retroactively to existing contracts.
(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 § 69.1805 (relating to electric generation supply procurement). Bids should be solicited for tranches of load within each customer class. Slice of system bid designs should not be utilized. However, DSPs may allow individual tranches to be stratified by soliciting separate bid prices for residential, commercial and industrial segments when there are too few customers to organize tranches along the groupings identified in § 69.1805.
(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 should coordinate their bid conferences and bidding dates to facilitate bid participation and economies of scale, yet also providing opportunities for additional wholesale bidding over reasonable time intervals.
(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 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.
(9) Wholesale energy suppliers may include a significant risk premium in their competitive bids to hedge against changes in transmission rates during the term of a default service supply contract. The public interest would be served by consideration of mechanisms that allow for the tracking and automatic adjustment of transmission rates during the term of the default service supply contract in order to reduce this premium.
§ 69.1808. Default service cost elements.
(a) The PTC should be designed to recover all generation, transmission and other related costs of default service. These cost elements include:
(1) Wholesale energy, capacity, ancillary, applicable RTO or ISO administrative and transmission costs.
(2) Congestion costs will ultimately be recovered from ratepayers. Congestion costs should be reflected in the fixed price bids submitted by wholesale energy suppliers.
(3) 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.
(4) Administrative costs, including billing, collection, education, regulatory, litigation, tariff filings, working capital, information system and associated administrative and general expenses related to default service.
(5) Applicable taxes, excluding Sales Tax.
(6) 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 September 15, 2007. The Commission may initiate a cost allocation case for an EDC on its own motion if such 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, default service rates, and correspondingly 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 from the introduction of new, differently priced energy supply products to the DSP's portfolio, and to correct the under and over collection of costs. For example, the PTC will be adjusted at least every quarter for residential customers and at least 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 and alternative energy compliance 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 recoveries 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 4% since the last rate adjustment. When the divergence is less than 4%, 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 recoveries 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 for a customer class rises by more than 25% following the expiration of a generation rate cap due to wholesale energy prices. When that occurs, 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 competitively neutral 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, that give dueconsideration to customer privacy, provide security of information and provide a customer an opportunity to restrict access to nonpublic customer information.
§ 69.1813. Rate and bill ready billing.
The public interest would be served by the consideration of the availability of rate and bill 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 mistakes 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 facilitating informal dispute resolution between the DSP and EGSs.
______1 Policies to Mitigate Potential Electricity Price Increases, Docket No. M-00061957.
2 Pennsylvania Power Company, the Pennsylvania Electric Company, and the Metropolitan Edison Company.
3 The Industrial Energy Consumers of Pennsylvania, the Met-Ed Industrial Users Group, the Penelec Industrial Customer Alliance, the Philadelphia Area Industrial Energy Users Group, and the PP&L Industrial Customer Alliance.
[Pa.B. Doc. No. 07-1699. Filed for public inspection September 14, 2007, 9:00 a.m.]
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