(a)  The purpose of this subchapter is to require that electricity providers enable customers to make informed choices regarding the purchase of electricity services offered by providing adequate and accurate customer information. Information shall be provided to customers in an understandable format that enables customers to compare prices and services on a uniform basis.

 The following words and terms, when used in this subchapter, have the following meanings, unless the context clearly indicates otherwise:

   Aggregator or market aggregator—An entity, licensed by the Commission, that purchases electric energy and takes title to electric energy as an intermediary for sale to retail customers.

   Basic services—Services necessary for the physical delivery of electricity service, including generation, transmission and distribution. Transition charges, although temporary in scope, are basic service charges (See the definition of transition charges in this section).

   Broker or marketer—An entity, licensed by the Commission, that acts as an agent or intermediary in the sale and purchase of electric energy but does not take title to electric energy.

   CTC—Competitive Transition Charge—A nonbypassable charge applied to the bill of every customer accessing the transmission or distribution network which (charge) is designed to recover an electric utility’s transition or stranded costs as determined by the Commission in sections 2804 and 2808 of the code (relating to standards for restructuring of electric industry; and competitive transition charge).

   Code—The Public Utility Code, 66 Pa.C.S. § §  101—3316.

   Consumer—A retail electric customer or potential customer of retail electricity service.

   Consumer contract—The written disclosure statement of the terms of service between a customer and an EGS which satisfies the definition of consumer contract in section 3 of the Plain Language Consumer Contract Act (73 P. S. §  2203).

   Customer—A retail electric customer.

   Customer information—Written, oral or electronic communications used by electricity providers to communicate to consumers prices and terms of service.

   Distribution charges—Basic service charges for delivering electricity over a distribution system to the home or business from the transmission system. These charges include basic service under §  56.15(4) (relating to billing information) and universal service, as applicable.

   EDC—Electric Distribution Company—The public utility providing facilities for the jurisdictional transmission and distribution of electricity to retail customers, except building or facility owners or operators that manage the internal distribution system serving the building or facility and that supply electric power and other related electric power services to occupants of the building or facility.

   EGS—Electric Generation Supplier or Supplier—

     (i)   A person or corporation, including a municipal corporation, which provides service outside its municipal limits except to the extent provided prior to the effective date of this chapter. (Editor’s Note: The reference to ‘‘this chapter’’ refers to the code.) This includes brokers and marketers, aggregators or other entities that sell to end-use customers electricity or related services utilizing the jurisdictional transmission or distribution facilities of an electric distribution company.

     (ii)   The term excludes building or facility owner/operators that manage the internal distribution system for the building or facility and that supply electric power and other related power services to occupants of the building or facility.

     (iii)   The term also excludes electric cooperative corporations except as provided in 15 Pa.C.S. Chapter 74 (relating to generation choice for customers of electric cooperatives).

   Electricity providers—The term refers collectively to the EDC, EGS, electricity supplier, marketer, aggregator or broker, as well as any third party acting on behalf of these entities.

   Generation charges—Basic service charges for generation supply to retail customers. This excludes charges for transmission or other charges related to electric service.

   Historical billing data—The minimum of 13 months of data as recorded by the EDC, which contains dollar amount billed. This data is kWh consumption on-peak and off-peak or at some other prescribed interval of consumption and associated cost and, if applicable, at demand levels at the intervals recorded and associated costs of those demand levels.

   ITC—Intangible Transition Charge—Charges authorized by the Commission to be imposed on all customer bills and collected, through a nonbypassable mechanism by the electric utility or its successor or by any other entity which provides electric service to a person that was a customer of an electric utility located within the certificated territory of the electric utility on January 1, 1997, or that, after January 1, 1997, became a customer of electric services within the territory and is still located within the territory, to recover qualified transition expenses pursuant to a qualified rate order, in a manner that does not shift interclass or intraclass costs and maintains consistency with the allocation methodology for utility production plant accepted by the Commission in the electric utility’s most recent base rate proceeding.

   Marketer or Broker—An entity, licensed by the Commission, that acts as an agent or intermediary in the sale and purchase of electric energy and does not take title to the electric energy.

   Nonbasic services—Optional recurring services which are distinctly separate and clearly not required for the physical delivery of electric service.

   Renewable resource—The term includes technologies such as solar photovoltaic energy, solar thermal energy, wind power, low-head hydropower, geothermal energy, landfill or other biomass-based methane gas, mine-based methane gas, energy from waste and sustainable biomass energy.

   Small business customer—The term refers to a person, sole proprietorship, partnership, corporation, association or other business entity that receives electric service under a small commercial, small industrial or small business rate classification, and whose maximum registered peak load was less than 25 kW within the last 12 months.

   Transition charges—Basic service charges for costs defined as transition or stranded costs, comprised of a CTC and an ITC, designed to recover an EDC’s transition or stranded costs as authorized by the Commission.

   Transition or stranded costs—An electric utility’s known and measurable net electric generation-related costs, determined on a net present value basis over the life of the asset or liability as part of its restructuring plan, which traditionally would be recoverable under a regulated environment but which may not be recoverable in a competitive electric generation market and which the Commission determines will remain following mitigation by the electric utility. The term includes those items enumerated in the definition of ‘‘transition or stranded costs,’’ in section 2803 of the code (relating to definitions).

   Transmission charges—Basic service charges for the cost of transporting electricity over high voltage wires from the generator to the distribution system of an EDC.

 In furnishing retail electricity service, EDCs and EGSs or any entity that otherwise provides retail electricity service information to customers, shall comply with the following:

   (1)  Use common and consistent terminology in customer communications, including marketing, billing and disclosure statements.

     (i)   Use the term EDC as described in §  54.2 (relating to definitions) as a standard term.

     (ii)   Use the terms as defined in the Commission’s ‘‘Consumer’s Dictionary for Electric Competition’’ (Dictionary), maintained on file in the Commission’s Office of Communications. EDCs shall provide this dictionary upon customer request. The ‘‘Common Electric Competition Terms’’ as described in subparagraph (iii) shall indicate the phone number and address to request the dictionary.

     (iii)   EDCs shall distribute the ‘‘Common Electric Competition Terms,’’ as part of its consumer education program.

 (a)  EGS prices billed must reflect the marketed prices and the agreed upon prices in the disclosure statement.

 (b)  The following requirements apply only to the extent to which an entity has responsibility for billing customers, to the extent that the charges are applicable. The default service provider will be considered to be an EGS for the purposes of this section. Duplication of billing for the same or identical charges by both the EDC and EGS is not permitted.

   (1)  EDC charges must appear separately from EGS charges.

   (2)  Charges for basic services must appear before charges for nonbasic services, and appear distinctly separate.

   (3)  Customer bills must contain the following charges, if these charges are applicable, and these charges must appear in a distinct section of the bill. The designation or label of each charge as either a basic charge or nonbasic charge appears in parenthesis following the name of the charge. This label of either basic or nonbasic is not required to accompany the name of the charge on the bill.

     (i)   Generation charges (basic).

       (A)   Generation charges shall be presented in a standard pricing unit for electricity in actual dollars or cents per kWh, actual average dollars or cents per kWh, kW or other Commission-approved standard pricing unit.

       (B)   Generation charges shall appear first among the basic charges with one exception. EDCs may place the customer charge first among the basic charges.

     (ii)   Transmission charges (basic).

     (iii)   Distribution charges (basic).

     (iv)   Customer charge or basic charge (charge for basic service in §  56.15 (relating to billing information)) (basic).

     (v)   Advanced metering charges (basic).

     (vi)   Transition charges (basic).

     (vii)   Taxes (comply with §  56.15) (basic).

     (viii)   Late payment charges (basic).

     (ix)   Security deposit (basic).

     (x)   Reconnection fee (basic).

     (xi)   Itemization of nonbasic charges (nonbasic).

     (xii)   Overall billing total.

   (4)  The entity reading the meter for billing purposes shall provide the following electricity use data figures:

     (i)   The total annual electricity use for the past 12 months in kWh, including the current billing cycle. This is a single cumulative number.

     (ii)   The average monthly electricity use for the past 12 months in kWh, including the current billing cycle. This is a single cumulative number.

   (5)  The requirements of §  56.15 shall be incorporated in customer bills to the extent that they apply.

   (6)  Definitions for the following charges and terms are required in a customer’s bill, if they appear as billing items, as contained in ‘‘Common Electric Competition Terms’’ and shall be in a distinctly separate section of the bill:

     (i)   Generation charges.

     (ii)   Transmission charges.

     (iii)   Distribution charges.

     (iv)   Customer charge/basic charge (charge for basic service in §  56.15).

     (v)   Advanced metering, if applicable.

     (vi)   Transition charges.

   (7)  ‘‘General Information’’ is the required title for customer contact information in a customer’s bill.

     (i)   The name, address and telephone number for the EGS and EDC shall be included.

     (ii)   Both EDC and EGS information in subparagraph (i) is required on all customer bills with the billing entity’s information first.

   (8)  When a customer chooses the option to receive a separate bill for generation supply, the EDC shall include in a customer’s bill the following information where the EGS charges would normally appear:

     (i)   The EGS’s name.

     (ii)   A statement that the customer’s EGS is responsible for the billing of EGS charges.

   (9)  When a customer chooses the option to receive a single bill from the EDC, the EDC shall include in the customer’s bill the name of the EGS where the EGS charges appear.

   (10)  For customers who have chosen electric generation services from a competitive supplier, the customer’s bill shall include the following statements which may appear together in a paragraph:

     (i)   ‘‘Generation prices and charges are set by the electric generation supplier you have chosen.’’

     (ii)   ‘‘The Public Utility Commission regulates distribution prices and services.’’

     (iii)   ‘‘The Federal Energy Regulatory Commission regulates transmission prices and services.’’

 (c)  The billing entity shall provide samples of customer bills to the Commission for review.

   The provisions of this §  54.4 amended September 14, 2007, effective September 15, 2007, 37 Pa.B. 4996. Immediately preceding text appears at serial pages (247125) to (247126).

 (a)  The agreed upon prices in the disclosure statement must reflect the marketed prices and the billed prices.

 (b)  The EGS shall provide the customer written disclosure of the terms of service at no charge whenever:

   (1)  The customer requests that an EGS initiate service.

   (2)  The EGS proposes to change the terms of service.

   (3)  Service commences from a default service provider.

 (c)  The contract’s terms of service shall be disclosed, including the following terms and conditions, if applicable:

   (1)  Generation charges shall be disclosed according to the actual prices.

   (2)  The variable pricing statement, if applicable, must include:

     (i)   Conditions of variability (state on what basis prices will vary).

     (ii)   Limits on price variability.

   (3)  An itemization of basic and nonbasic charges distinctly separate and clearly labeled.

   (4)  The length of the agreement, which includes:

     (i)   The starting date.

     (ii)   The expiration date, if applicable.

   (5)  An explanation of sign-up bonuses, add-ons, limited time offers, other sales promotions and exclusions, if applicable.

   (6)  An explanation of prices, terms and conditions for special services, including advanced metering deployment, if applicable.

   (7)  The cancellation provisions, if applicable.

   (8)  The renewal provisions, if applicable.

   (9)  The name and telephone number of the default service provider.

   (10)  An explanation of penalties, fees or exceptions, printed in type size larger than the type size appearing in the terms of service.

   (11)  Customer contact information that includes the name of the EDC and EGS, and the EGS’s address, telephone number, Commission license number and Internet address, if available. The EGS’s information shall appear first and be prominent.

   (12)  A statement that directs a customer to the Commission if the customer is not satisfied after discussing the terms of service with the EGS.

   (13)  The name and telephone number for universal service program information.

 (d)  Customers shall be provided a 3-day right of rescission period following receipt of the disclosure statement.

   (1)  The 3-day right of rescission is 3 business days.

   (2)  The 3-day right of rescission begins when the customer receives the written disclosure.

   (3)  The customer may cancel in writing, orally or electronically, if available.

   (4)  Waivers of the 3-day right of rescission are not permitted.

 (e)  Definitions for generation charges and transmission charges, if applicable, are required and shall be defined in accordance with the ‘‘Common Electric Competition Terms.’’ Definitions for each of the nonbasic services, if applicable, are required. The definition section of the bill must be distinctly separate.

 (f)  The EGS shall include in the customer’s disclosure statement the following statements which may appear together in a paragraph:

   (1)  ‘‘Generation prices and charges are set by the electric generation supplier you have chosen.’’

   (2)  ‘‘The Public Utility Commission regulates distribution prices and services.’’

   (3)  ‘‘The Federal Energy Regulatory Commission regulates transmission prices and services.’’

 (g)  Disclosure statements must include the following customer notification:

   (1)  ‘‘If you have a fixed term agreement with us and it is approaching the expiration date or whenever we propose to change our terms of service in any type of agreement, you will receive written notification from us in each of our last three bills for supply charges or in corresponding separate mailings that precede either the expiration date or the effective date of the proposed changes. We will explain your options to you in these three advance notifications.’’

 (h)  If the default service provider changes, the new default service provider shall notify customers of that change, and provide customers with its name, address, telephone number and Internet address, if available.

   The provisions of this §  54.5 amended September 14, 2007, effective September 15, 2007, 37 Pa.B. 4996. Immediately preceding text appears at serial pages (324545) to (324546).

 (a)  EGSs shall respond to reasonable requests made by consumers for information concerning generation energy sources.

   (1)  EGSs shall respond by informing consumers that this information is included in the annual licensing report and that this report exists at the Commission. Providers shall explain that the report is available to them and offer to provide it, if requested.

   (2)  The default service provider shall file at the Commission the annual licensing report as required by the Commission’s licensing regulations in this chapter and shall otherwise comply with paragraph (1).

   (3)  EGSs operating for less than 1 year may respond to customer inquiries about generation energy sources by furnishing the information as described in subsection (b).

 (b)  Verification of the anticipated generation energy source, of the identifiable resources (if and when they have been ‘‘claimed’’) and the fact that energy characteristics were not sold more than once, shall be conducted by an independent auditor at the end of each calendar year and contained in the annual report to the Commission, relating to information disclosure requirements in subsection (a) and the licensing regulations in this chapter.

 (c)  Whenever EGSs market their generation as having special characteristics, such as ‘‘produced in Pennsylvania’’ or ‘‘environmentally friendly’’ and the like, providers shall have information available to substantiate their claims.

   (1)  Disclosure of generation energy sources shall be identifiable, which is defined as electricity transactions which are traceable to specific generation sources by any auditable contract trail or equivalent, such as a tradable commodity system, that provides verification that the electricity source claimed has been sold only once to a retail customer. If generation energy sources are not identifiable, the provider shall disclose this fact.

 (d)  Electricity providers, whether they make distinguishing claims or not, shall include in their general communications with consumers that electricity is the product of a mix of generation energy sources, that is delivered over a system of wires.

 (e)  Electricity providers shall respond to reasonable consumer requests for energy efficiency information, by indicating that these materials are available upon request from the Commission or the EDC.

 (f)  The use of general, unsubstantiated and unqualified claims of environmental benefits, such as ‘‘green’’ and ‘‘environmentally friendly,’’ is prohibited. The Commission supports the application of the Federal Trade Commission’s (FTC) Guides for the Use of Environmental Marketing Claims (see 16 CFR 260.1—260.8 (relating to guides for the use of environmental marketing claims)), in the enforcement of this section and the following specific principles:

   (1)  Section 260.6(a) (relating to general principles) which states that qualifications or disclosure should be clear, prominent, and of relative type size and proximity to the claim being qualified. In addition, contrary assertions which undercut the qualifications should not appear.

   (2)  Section 260.6(c) which states that environmental claims should not overstate the environmental attribute or benefit, expressly or by implication.

   (3)  Section 260.6(d) which suggests that marketing materials which make comparative claims should clearly state the basis for the comparison, be able to be substantiated, and be accurate at the time they are made.

   (4)  Section 260.7(a) (relating to environmental marketing claims) which labels unqualified claims of environmental benefit as deceptive.

   (5)  Section 260.7(f) which addresses claims regarding source reduction, such as reduced toxicity or reductions of other environmentally negative effects.

 (g)  Residential and small business customers are entitled to receive at no charge and at least once a year, historical billing data from whomever reads the meter for billing purposes.

   (1)  The EDC is only obligated to provide information that is readily available in its billing system.

   (2)  The historical billing data shall be conveyed in terms of kWh, and kW, as applicable, and associated charges for the current billing period and for the year preceding the current billing period.

   (3)  The historical billing data will be updated with each billing cycle.

 (h)  Electricity providers shall notify consumers either in advertising materials, disclosure statements or bills that information on generation energy sources, energy efficiency, environmental impacts or historical billing data is available upon request.

   The provisions of this §  54.6 amended September 14, 2007, effective September 15, 2007, 37 Pa.B. 4996. Immediately preceding text appears at serial pages (324546) and (247129) to (247130).

 (a)  Advertised prices shall reflect prices in disclosure statements and billed prices.

 (b)  Marketing materials that offer terms of service for acceptance by consumers shall include prices, as follows:

   (1)  If using a fixed price, the EGS shall show in a table the price per kWh for an average customer using 500, 1,000 or 2,000 kWh of electricity.

   (2)  If using a variable price mechanism, the EGS shall factor in all costs associated with the rate charged to the customer, and show the average price per kWh for usages of 500, 1,000 and 2,000 kWh of electricity in a table format.

   (3)  The EGS shall note the effective date of the prices shown in the table provided under paragraph (1) or (2).

 (c)  Advertising materials targeted for residential and small business sales shall be made available upon request of the Commission in the event of a formal or informal complaint or investigation.

 (a)  An EDC or EGS may not release private customer information to a third party unless the customer has been notified of the intent and has been given a convenient method of notifying the entity of the customer’s desire to restrict the release of the private information. Specifically, a customer may restrict the release of either the following:

   (1)  The customer’s telephone number.

   (2)  The customer’s historical billing data.

 (b)  Customers shall be permitted to restrict information as specified in subsection (a) by returning a signed form, orally or electronically.

 (c)  Nothing in this section prohibits the EGS and EDC from performing their mandatory obligations to provide electricity service as specified in the disclosure statement and in the code.

 EDCs and EGSs shall disclose to consumers the following with respect to the rights of consumers in the handling and resolution of complaints:

   (1)  Residential and small business customers shall directly contact the party responsible for the service in question as an initial step for complaint and problem resolution. If the customer mistakenly contacts the wrong entity, the customer shall be promptly referred to the appropriate contact. In the event of a power outage, the customer shall be directed to the EDC.

   (2)  Complaints that pertain to Chapter 56 (relating to standards and billing practices for residential utility service) matters shall be handled and resolved in accordance with the applicable standards in Chapter 56.

   (3)  EDCs and EGSs shall give the Commission access to disclosure statements, billing and other customer information resources for compliance reviews as deemed necessary by the Commission. When complaints arise and are brought before the Commission for resolution, the obligation of the EGS shall be extended to the provision of pricing information.

   This section cited in 52 Pa. Code §  54.1 (relating to purpose).

Subchapter B. ELECTRICITY GENERATION
SUPPLIER LICENSING

Sec.

 The following words and terms, when used in this subchapter, have the following meanings, unless the context clearly indicates otherwise.

   Aggregator—An entity licensed by the Commission, that purchases electric energy and takes title to electric energy as an intermediary for sale to retail customers. See section 2803 of the code (relating to definitions).

   Applicant—A person or entity seeking to obtain a license to supply retail electricity or electric generation service.

   Broker—An entity, licensed by the Commission, that acts as an intermediary in the sale and purchase of electric energy but does not take title to electric energy. See section 2803 of the code.

   Code—The Public Utility Code (66 Pa.C.S. Part I).

   Default service provider—The incumbent EDC within a certificated service territory or a Commission approved alternative supplier of electric generation.

   Department—The Department of Revenue of the Commonwealth.

   EDC—Electric distribution company.

   EGS—Electric generation supplier—

     (i)   A person or corporation, including municipal corporations which choose to provide service outside their municipal limits except to the extent provided prior to the effective date of this chapter (Editor’s Note: The reference to ‘‘this chapter’’ refers to the code.), brokers and marketers, aggregators or any other entities, that sell to end-use customers electricity or related services utilizing the jurisdictional transmission and distribution facilities of an EDC, or that purchase, broker, arrange or market electricity or related services for sale to end-use customers utilizing the jurisdictional transmission and distribution facilities of an EDC.

     (ii)   The term excludes building or facility owner/operators that manage the internal distribution system serving the building or facility and that supply electric power and other related power services to occupants of the building or the facility.

     (iii)   The term excludes electric cooperative corporations except as provided in 15 Pa.C.S. Chapter 74 (relating to generation choice for customers of electric cooperatives). See section 2803 of the code.

   Interim license—A temporary license granted to an EGS under interim standards adopted in the Commission’s Final Order on Licensing Requirements for Electricity Generation Suppliers, entered February 13, 1997 at Dkt. No. M-00960890 F0004.

   License—A license granted to an EGS under this subchapter.

   Licensee—A person or entity which has obtained a license to provide retail electricity or electric generation service.

   Market aggregator—An entity licensed by the Commission, that purchases electric energy and takes title to electric energy as an intermediary for sale to retail customers. See section 2803 of the code.

   Marketer—An entity, licensed by the Commission, that acts as an intermediary in the sale and purchase of electric energy but does not take title to electric energy. See section 2803 of the code.

   Marketing—The publication, dissemination or distribution of informational and advertising materials regarding the EGS’s services and products to the public by print, broadcast, electronic media, direct mail or by telecommunication.

   Offer to provide service—The extension of an offer to provide services or products communicated orally, or in writing to a customer.

   Renewable resource—As defined in section 2803 of the code.

 (a)  An EGS may not engage in marketing, or may not offer to provide, or provide retail electricity or electric generation service until it is granted a license by the Commission.

 (b)  An application for a license shall be made on the form provided by the Commission. A copy of the application may be obtained from the Commission’s Secretary. The application form will also be made available on the Commission’s Internet web site. An application shall be verified by an oath or affirmation as required in §  1.36 (relating to verification). See section 2809(b) of the code (relating to requirements for electric generation suppliers).

 (c)  An original and eight copies of the completed application and supporting attachments shall be filed. An application for a license shall be accompanied by the application fee as established in §  1.43 (relating to schedule of fees payable to the Commission).

 (d)  Copies of the completed application with supporting documentation shall be served on the following: the Office of Consumer Advocate, the Office of Small Business Advocate, the Department and the Office of the Attorney General and the EDCs through whose transmission and distribution facilities the applicant intends to supply customers.

 (e)  Incomplete applications and those without supporting attachments, when needed, will be rejected without prejudice. The license application, with supporting attachments, shall be completed in its entirety.

 (f)  When an answer on the application requires the disclosure of privileged or confidential information not otherwise available to the public, the applicant may designate at each point in the application where information is disclosed that is confidential and privileged.

   (1)  One copy of this confidential or privileged information conspicuously marked at the top as ‘‘CONFIDENTIAL’’ may be submitted to the Office of the Secretary with the application. An applicant shall provide reasons for protecting this information.

   (2)  The request for confidentiality will be treated as a petition for protective order and will be ruled on by the Commission in conjunction with the license application.

   (3)  Pending disposition, the information will be used solely for the purpose of evaluating the license application, and the confidentiality of this information will be maintained consistent with regulations in this title pertaining to confidentiality.

 (g)  An EGS who has been granted an interim license shall apply for a license under this subchapter by updating its prior license application to include additional and updated information required by §  54.33 (relating to application form). An updated application shall be submitted by December 7, 1998.

 (h)  An EDC acting within its certificated service territory as a default service provider is not required to obtain a license.

 (a)  The application form includes information that will be used in the evaluation of the financial fitness and technical fitness to render service. This information includes the following:

   (1)  An identification of the geographic area that the applicant proposes to serve.

   (2)  An identification of the type of service that the applicant proposes to furnish.

   (3)  An identification of the class of customers to which the applicant proposes to provide these services.

   (4)  An identification of the applicant’s utility affiliates.

   (5)  A description of the applicant’s business structure.

   (6)  Financial information sufficient to demonstrate financial fitness. This information may include credit ratings and history, audited financial statements, and insurance pertinent to the conduct of the applicant’s business as an electric generation supplier.

   (7)  Evidence of competency and experience in providing the scope and nature of the applicant’s proposed services. This evidence may include descriptions of the applicant’s prior experience, proposed staffing and employe training commitments, business plans, and agreements, arrangements and contracts for generation, transmission and related services. Documentation of the applicant’s membership in the East Central Area Reliability Coordination Agreement (ECAR), the Mid Atlantic Area Council (MAAC) or other National American Electric Reliability Council (NERC) regional reliability councils shall be submitted if applicable to the scope and nature of the applicant’s proposed services.

   (8)  Evidence of information demonstrating the applicant’s ability to comply with Commission’s applicable requirements concerning customer billing, customer education, billing and terms of service, and customer information. This evidence may include prior regulatory experience of the applicant, prior business experience in energy or other service-oriented industries, staffing and staff training commitments, agreements, arrangements and contracts for customer education and information service, customer satisfaction survey results, government agency reports and complaint statistics compiled by the Better Business Bureau or similar business organizations.

   (9)  Certification that notice of the application was published in accordance with §  54.35 (relating to publication of notice of filing) shall be filed with the Commission’s Secretary. The certification shall be notarized and include a photostatic copy of the notices as published. An application will not be considered complete for Commission review without this certification.

 (b)  The application also directs, under sections 2806(g)(3)(i), 2809(c)(1) and 2810(c)(6) of the code (relating to implementation, pilot programs and performance-based rates; requirements for electric generation suppliers; and revenue-neutral reconciliation), that the applicant provide tax information. This tax information includes:

   (1)  The name, address, telephone number, electronic numbers and addresses used to transmit tax and related information of the persons responsible for preparing and filing the applicant’s Pennsylvania tax returns.

   (2)  Trade names or fictitious names used by the applicant.

   (3)  The type of business association (for example, sole proprietor, partnership and corporation).

   (4)  The names of the owners, general partners or corporate officers.

   (5)  The number of the applicant’s current and anticipated employes working in this Commonwealth.

   (6)  An identification of the applicant’s assets in this Commonwealth.

   (7)  The principal office in this Commonwealth or of its registered agent.

   (8)  An applicant’s Department tax identification numbers including Sales Tax license number, employer identification number and corporate box number. If tax numbers have not yet been obtained, an applicant shall provide the filing date of its application for these numbers.

 (c)  Tax information provided under subsection (b) shall be filed with the Secretary of the Department at the time that application is made with the Commission.

 (a)  The applicant is under a duty to inform the Commission of a material change in the information provided in the application during the pendency of the application, or while the licensee is operating in this Commonwealth.

 (b)  A material change in the organizational structure or operation that affects an applicant’s or a licensee’s operation in this Commonwealth shall be reported to the Commission within 30 days of the date of the change. Specifically, notification shall be given to the Commission of a change in the following:

   (1)  The ownership of generation or transmission facilities or other inputs to electric power production.

   (2)  An affiliation with an EDC, or an entity which owns generation or transmission facilities or other inputs to electric power production.

   (3)  An affiliation with an entity that has a franchised service area.

 (a)  Notice of filing an application shall be published in newspapers of general circulation covering each county in which the applicant intends to provide service as required by §  5.14(a)(2) (relating to applications requiring notice). Applicants may contact the Commission’s Press Secretary to confirm the identity of the newspapers of general circulation in which notice shall be published.

 (b)  The notice shall be written in plain language and include the name, address and telephone number of the applicant, a description of the proposed services to be provided and the geographic area to be served. The notice shall include the application docket number and a statement that protests related to the technical or financial fitness of the applicant shall be filed within 15 days of the publication date of the notice with the Commission’s Secretary, Public Utility Commission, P. O. Box 3265, Harrisburg, PA 17105-3265. The notice in an acceptable electronic format shall be submitted to the Commission’s Secretary for posting on the Commission’s Internet web site and, if appropriate, on the Commission’s electronic bulletin board.

 (a)  Consistent with §  5.14(b) (relating to applications requiring notice), a 15-day protest period commences on the date notice of the application filing is published in newspapers. An interested party may file a protest to an application in compliance with §  5.52(a) (relating to content of a protest to an application) and shall set out clearly and concisely the facts upon which challenge to the fitness of the applicant is based. An applicant may file an answer to the protest within 10 days of when the protest is filed. Protests which do not fully comply with §  5.52(a) will be rejected.

 (b)  Protests may challenge only the applicant’s financial and technical fitness to provide the service for which a license is requested. Consistent with the requirements of due process, sanctions, such as revocation or suspension of a supplier’s license or the imposition of a fine, may be imposed on parties who intentionally misuse the protest process by repeated filing of competitive protests.

 (a)  A license will be issued, authorizing the whole or any part of service requested, if the Commission finds that:

   (1)  The applicant is fit, willing and able to properly perform the service proposed in conformance with applicable provisions of the code and the lawful Commission orders and regulations, specifically including Chapter 56 (relating to Standards and Billing Practices for Residential Utility Service).

   (2)  The proposed service is consistent with the public interest and the policy declared in Chapter 28 of the code (relating to the Electricity Generation Customer Choice and Competition Act. See section 2809(b) of the code (relating to requirements for electric generation suppliers).

 (a)  A licensee shall be required to pay assessments to be used to defray regulatory costs. See section 510 of the code (relating to assessment for regulatory expenses upon public utilities). Assessments will be based upon the administrative costs incurred by the Commission related to generation suppliers. These costs include:

   (1)  Maintaining records related to licensees and administering other provisions of the code related to maintenance of adequate reserve margins.

   (2)  Compliance with Chapter 56 (relating to standards and billing practices for residential utility service).

   (3)  Fulfilling consumer information and education obligations.

 (b)  Yearly assessments shall be paid by the licensee within 30 days of receipt of notice of the amount lawfully charged against it as a condition of maintaining a license to supply electricity or electric generation. See section 510(c) of the code.

   Conflict with Statute

 (a)  A licensee shall report its level of gross receipts to the Commission on a quarterly basis. Gross receipt information shall be filed with the Commission within the 30 days following the end of the first full quarter, and of each subsequent quarter that the license is in effect.

 (b)  A licensee shall file an annual report on or before April 30 of each year, for the previous calendar year. The annual report shall contain the following information (See section 2810(c)(6) of the code (relating to revenue-neutral reconciliation):

   (1)  Updates to the tax information requested in the application in §  54.33(b) (relating to application form).

   (2)  The total amount of gross receipts from the sales of electricity for the preceding calendar year.

   (3)  The total amount of electricity sold, stated in kilowatt hours, during the preceding calendar year.

   (4)  The percentage of total electricity supplied by each energy source, including a detailed breakdown of renewable resources as defined in section 2803 of the code (relating to definitions).

 (c)  A licensee shall be required to meet periodic reporting requirements as may be issued by the Commission to fulfill the Commission’s duty under Chapter 28 of the code (relating to Electricity Generation Customer Choice and Competition Act) pertaining to reliability and to inform the Governor and Legislature of the progress of the transition to a fully competitive electric market.

 (a)  A license will not be issued or remain in force until the licensee furnishes a bond or other security approved by the Commission. See section 2809(c) of the code (relating to requirements for electric generation suppliers).

 (b)  The purpose of the security requirement is to ensure the licensee’s financial responsibility, the payment of gross receipts tax as required by section 2810 of the code (relating to revenue-neutral reconciliation), and the supply of electricity at retail in accordance with contracts, agreements or arrangement. See section 2809(c) of the code.

 (c)  The initial security level required from each applicant is $250,000. Modifications of this amount commensurate with the nature and scope of business anticipated to be conducted in this Commonwealth may be granted where substantial evidence is submitted in support of the modification. A request for modification of this initial security level may be made in conjunction with the filing of the application. The license will be issued contingent on the submission of proof that the applicant has obtained a bond, or other approved security in the amount directed by the Commission.

 (d)  After the first year that the license is in effect, the security level for each licensee will be reviewed annually and modified primarily based on the licensee’s reported annual gross receipts information. The security level will be 10% of the licensee’s reported gross receipts. See section 2809 (c)(1)(i) of the code. Maintenance of a license will be contingent on the licensee providing proof to the Commission that a bond or other approved security in the amount directed by the Commission has been obtained. A licensee may seek approval from the Commission of an alternative level of bonding commensurate with the nature and scope of its operations.

 (e)  Payments pursuant to the security may result from the licensee’s failure to pay the full amount of Gross Receipt Taxes, or failure to supply electricity or other services in accordance with contracts, agreements or arrangements.

 (f)  The bond or security shall include the following:

   (1)  The Pennsylvania Public Utility Commission, Commonwealth as the sole beneficiary.

   (2)  The purpose of the bond as follows:

  This bond (or other security) is written in accordance with Section 2809(c)(1)(i) of the Public Utility Code, 66 Pa.C.S. §  2809(c)(1)(i), to assure compliance with applicable provisions of the Public Utility Code, 66 Pa.C.S. § §  101, et seq., and the rules and regulation of the Pennsylvania Public Utility Commission by the Principle as a licensed electric generation supplier; to ensure the payment of Gross Receipts Tax as required by Section 2810 of the Public Utility Code, 66 Pa.C.S. §  2810; and to ensure the supply of electricity at retail in accordance with contracts, agreements or arrangements.

   (3)  A listing of the prioritization of claims for payment under the security from highest priority to lowest priority as follows:

     (i)   The Commonwealth.

     (ii)   EDCs for the reimbursement of Gross Receipts Tax.

 (c)  Private individuals.

   (4)  A statement that the security shall be interpreted under law of the Commonwealth, or in the alternative, no choice of law is specified.

 (g)  The applicant may request the use of a security other than a bond. See section 2809 (c)(1)(i) of the code. The application shall include specific information about the licensee’s need to use a security other than a bond; and shall provide the name, business address, the nature of the business of the entity issuing the security, and if available, the financial rating of the entity. The applicant shall demonstrate that the financial protection afforded by the security is equivalent to that of a bond.

 (a)  A license may not be transferred without prior Commission approval. See section 2809(d) of the code (relating to requirements for electric generation suppliers). Approval for transfer shall be obtained by petition to the Commission. The granting of such a petition does not eliminate the need for the transferee to complete and file with the Commission an application that demonstrates the transferee’s financial and technical fitness to render service under the transferred license.

 (b)  A licensee may not abandon service without providing 90 days prior written notice to the Commission, the licensee’s customers, the affected distribution utilities and default service providers prior to the abandonment of service. The licensee shall provide individual notice to its customers with each billing, in each of the three billing cycles preceding the effective date of the abandonment.

   The provisions of this §  54.41 amended September 14, 2007, effective September 15, 2007, 37 Pa.B. 4996. Immediately preceding text appears at serial page (247140).

 (a)  A licensee shall comply with the applicable requirements of the code and Commission regulations and orders. Consistent with due process, a license may be suspended or revoked, and fines may be imposed against the licensee for:

   (1)  The failure to pay the yearly assessment.

   (2)  The failure to furnish and maintain a bond or other security approved by the Commission in the amount directed by the Commission.

   (3)  The nonpayment of taxes under Article II of the Tax Reform Code of 1971 (72 P. S. § §  7201—7281.2) and Article XI of the Tax Reform Code of 1971 (72 P. S. § §  8101—8104) and any taxes imposed by Chapter 28 of the code (relating to Electricity Generation Customer Choice and Competition Act). See sections 2806(g)(3) and 2809(c)(1) of the code (relating to implementation, pilot program and performance based rates; and requirements for electric generation suppliers).

   (4)  The failure to waive confidentiality with respect to tax information in the possession of the Department. See section 2810(c)(6)(iv) of the code (relating to revenue-neutral reconciliation).

   (5)  The failure to provide the address of its principal office in this Commonwealth or of its registered agent.

   (6)  The failure to follow the principles in §  54.43 (relating to standards of conduct and disclosure for licensees).

   (7)  A violation of applicable provisions of the code, this title and lawful Commission orders. See section 2809(b) of the code.

   (8)  A violation of Pennsylvania consumer protection law.

   (9)  The transfer of a customer without the customer’s consent. See section 2807(d)(1) of the code (relating to duties of electric distribution companies).

 To protect consumers of this Commonwealth, licensees shall adhere to the following principles in the provision of electric generation service:

   (1)  A licensee shall provide accurate information about their electric generation services using plain language and common terms in communications with consumers. When new terms are used, the terms shall be defined again using plain language. Information shall be provided in a format that enables customers to compare the various electric generation services offered and the prices charged for each type of service.

 (b)  A licensee shall respond to reasonable consumer requests for information regarding energy sources by percentage, and plant emissions of its electric generation supply.

 (c)  A licensee shall provide notification of change in conditions of service, intent to cease operation as an electric generation supplier, explanation of denial of service, proper handling of deposits and proper handling of complaints in accordance with this title.

 (d)  A licensee shall maintain the confidentiality of a consumer’s personal information including the name, address and telephone number, and historic payment information, and provide the right of access by the consumer to his own load and billing information.

 (e)  A licensee may not discriminate in the provision of electricity as to availability and terms of service based on race, color, religion, national origin, sex, marital status, age, receipt of public assistance income, and exercise of rights under Subchapter IV of the Consumer Credit Protection Act (15 U.S.C.A. § §  1691—1691f), relating to Equal Credit Opportunity. See 12 CFR 202-1—202.14 (relating to equal credit opportunity Regulation B).

 (f)  A licensee is responsible for any fraudulent deceptive or other unlawful marketing or billing acts performed by the licensee, its employes, agents or representatives. Licensee shall inform consumers of state consumer protection laws that govern the cancellation or rescission of electric generation supply contracts. See section 7 of the Unfair Trade Practices and Consumer Protection Law (73 P. S. §  201-7).

 (g)  A licensee shall comply with relevant Commission regulations, orders and directives that may be adopted.

   This section cited in 52 Pa. Code §  54.42 (relating to license suspension; license revocation).

Subchapter C. UNIVERSAL SERVICE AND ENERGY CONSERVATION REPORTING REQUIREMENTS

Sec.

 (a)  The Commission will determine if the EDC meets the goals of universal service and energy conservation programs.

 (b)  The general goals of universal service and energy conservation programs include the following:

   (1)  To protect consumers’ health and safety by helping low-income customers maintain electric service.

   (2)  To provide for affordable electric service by making available payment assistance to low-income customers.

   (3)  To assist low-income customers conserve energy and reduce residential utility bills.

 (a)  Plan submission.

   (1)  Each EDC shall submit to the Commission for approval an updated universal service and energy conservation plan every 3 years beginning February 28, 2000, on a staggered schedule.

   (2)  The plan should cover the next 3-calendar years.

   (3)  The plan should state how it differs from the previously approved plan.

   (4)  The plan should include revisions based on analysis of program experiences and evaluations.

   (5)  If the Commission rejects the plan, the EDC shall submit a revised plan under the order rejecting or directing modification of the plan as previously filed. If the order rejecting the plan does not state a timeline, the EDC shall file its revised plan within 45 days of the entry of the order.

   (6)  The Commission will act on the plans within 90 days of the EDC filing date.

 (b)  Plan contents. The components of universal service and energy conservation may include the following: CAP, LIURP, CARES, Hardship Funds and other programs, policies and protections. For each component of universal service and energy conservation, the plan shall include, but not be limited to, the following:

   (1)  Program description.

   (2)  Eligibility criteria.

   (3)  Projected needs assessment.

   (4)  Projected enrollment levels.

   (5)  Program budget.

   (6)  Plans to use community-based organizations.

   (7)  Organizational structure of staff responsible for universal service programs.

   (8)  Explanation of any differences between the EDC’s approved plan and the implementation of that plan. The EDC should include a plan to address those differences.

 Each EDC shall report annually to the Commission on the degree to which universal service and energy conservation programs within its service territory are available and appropriately funded. Annual EDC reports shall contain information on programs and collections for the prior calendar year. Unless otherwise stated, the report shall be due April 1 each year, beginning April 1, 2001. Where noted, the data shall be reported by classification of accounts. Each EDC’s report shall contain the following information:

   (1)  Collection reporting shall be categorized as follows:

     (i)   The total number of payment arrangements and the total number of successful payment arrangements. To ensure that successful payment arrangements are not overstated, EDCs should report on the calendar year prior to the reporting year.

     (ii)   Annual collection operating expenses by classification of accounts. Collection operating expenses include administrative expenses associated with termination activity, negotiating payment arrangements, budget counseling, investigation and resolving informal and formal complaints associated with payment arrangements, securing and maintaining deposits, tracking delinquent accounts, collection agencies’ expenses, litigation expenses other than Commission related, dunning expenses and winter survey expenses.

     (iii)   The total dollar amount of the gross residential write-offs and total dollar amount of the net residential write-offs, by classification of accounts.

     (iv)   The total number of residential customers by month for the 12 months covered by the report, by classification of accounts.

     (v)   The total number of residential accounts in arrears by month for the 12 months covered by the report, by classification of accounts.

     (vi)   The total dollar amount of residential accounts in arrears by month for the 12 months covered by the report, by classification of accounts.

     (vii)   The total number of residential customers who are payment troubled by month for the 12 months covered by the report, by classification of accounts.

     (viii)   The total number of terminations completed by month for the 12 months covered by the report, by classification of accounts.

     (ix)   The total number of reconnections by month for the 12 months covered by the report, by classification of accounts.

     (x)   The total number of low-income households. EDCs may estimate this number using census data or other information the EDC finds appropriate.

   (2)  Program reporting shall be categorized as follows:

     (i)   For each universal service and energy conservation component, program data shall include information on the following:

       (A)   Program costs.

       (B)   Program recipient demographics, including the number of family members under age 18 and over age 62, family size, income and source of income.

       (C)   Participation levels by month for the 12 months covered by the report.

     (ii)   Additional program data for individual universal service and energy conservation components shall include the following information:

       (A)   LIURP. Reporting requirements as established at §  58.15 (relating to program evaluation).

         (I)   LIURP reporting data shall be due by April 30.

         (II)   Actual production and spending data for the recently completed program year and projections for the current year shall be due annually by the end of February.

       (B)   CAP.

         (I)   Energy assistance benefits.

         (II)   Average CAP bills.

         (III)   Payment rate.

         (IV)   CAP benefits.

         (V)   Total cash payments by CAP customers.

         (VI)   Number of full, on-time payments

         (VII)   Percentage of CAP bill paid by customer.

       (C)   CARES.

         (I)   Energy assistance benefits.

         (II)   Direct dollars applied to CARES accounts.

         (III)   CARES benefits.

       (D)   Hardship funds.

         (I)   Ratepayer contributions.

         (II)   Special contributions.

         (III)   Utility contributions.

         (IV)   Outreach contacts.

         (V)   Hardship fund benefits.

 (a)  Each EDC shall have an independent third-party conduct an impact evaluation of its universal service and energy conservation programs and provide a report of findings and recommendations to the Commission and EDC.

 (b)  The first impact evaluation will be due beginning October 31, 2002, on a staggered schedule. Subsequent evaluation reports shall be presented to the EDC and the Commission at no more than 6 year intervals.

 (c)  To ensure an independent evaluation, neither the EDC nor the Commission shall exercise control over content or recommendations contained in the independent evaluation report. The EDCs may provide the Commission with a companion report that expresses where they agree or disagree with independent evaluation report content or recommendations.

 (d)  An independent third-party evaluator shall conduct the impact evaluation.

 Beginning March 1, 2000, each EDC with less than 60,000 accounts shall report to the Commission every 3 years the following information in lieu of § §  54.74—54.76 (relating to universal service and energy conservation plans; annual residential collection and universal service and energy conservation program reporting requirements; and evaluation reporting requirements):

   (1)  The universal service and energy conservation plan.

   (2)  Expenses associated with low-income customers.

   (3)  A description of the universal service and energy conservation services provided to low-income residential customers.

   (4)  The number of services or benefits provided to low-income residential customers.

 The Commission will annually produce a summary report on the universal service performance of each EDC using the statistics collected as a result of these reporting requirements. The reports will be public information. The Commission will provide the reports to any interested party and post the reports on the Commission’s Internet Website.

Subchapter D. ADJUSTMENT OF ELECTRIC DISTRIBUTION COMPANY RATES FOR CHANGES IN STATE TAX LIABILITY

Sec.

 (a)  The Commission will permit an EDC to recover from customers changes in its State tax liability arising from sections 2806(g), 2809(c) and 2810 of the code (relating to implementation, pilot programs and performance-based rates; requirements for electric generation suppliers; and revenue-neutral reconciliation) and § §  69.51—69.56 (relating to inclusion of State taxes and gross receipts taxes in base rates) to the extent that the resulting rates do not exceed the rate or price cap.

 (b)  An EDC seeking recovery of changes in its State tax liability under this section shall provide the following information to the Commission:

   (1)  A description of the surcharge proposed by the EDC, and a statement of reasons for the proposed rate change.

   (2)  A statement that the surcharge becomes effective for service rendered beginning 60 days after the filing of the tariffs or tariff supplements.

   (3)  If applicable, the calculations supporting the amount of its tax liability arising from the RNR.

   (4)  If applicable, the amount of payments under sections 2806(g) and 2809(c) of the code for the immediately preceding 12-month period ending on June 30, plus interest accrued at 6% per year from the time of payment until the time the payments are reflected in customer rates, supported by a copy of the notification received from the Department assessing these taxes and related interest.

   (5)  If applicable, an affidavit which states that the EDC has not recovered the taxes through tariff indemnification tariff provisions or other means, and that the Department has assessed the taxes.

 (a)  An EDC proposing to increase its rates above the rate cap due to the RNR shall file a single issue rate proceeding under section 1308(a) of the code (relating to voluntary changes in rates).

 (b)  The EDC’s filing provides information which enables the Commission to determine if the filing is an accurate claim for the amount of its tax liability arising from the RNR and whether recovery of its RNR tax liability causes the resulting rates to exceed the rate cap.

 (c)  Within 30 days of receiving the Department’s notice of the change in the applicable tax rate established by the RNR, an EDC proposing to increase its rates as described in this section shall provide the following information to the Commission:

   (1)  A statement that the reason for the proposed rate increase is to permit the EDC to recover that portion of its RNR tax liability that produces rates above the rate cap.

   (2)  A proof of revenue calculation by rate class demonstrating the impact of the proposed rate increase upon each class of customers. The EDC shall, at a minimum, show both the dollar and percentage change being proposed for each tariffed rate.

   (3)  A description of the surcharge for recovering the increased tax liability.

   (4)  A notice that the surcharge becomes effective 60 days from the date the EDC files the proposed rate increase.

 (a)  The Commission will permit an EDC to recover, through its State Tax Adjustment Surcharge or other appropriate mechanism, changes in its State tax liability and related interest under sections 2806(g) and 2809(c) of the code (relating to implementation, pilot programs and performance-based rates; and requirements for electric generation suppliers) when that recovery produces rates above the rate cap, upon certification by affidavit that the following apply:

   (1)  The EDC has not recovered the taxes due pursuant to its tariff indemnification provisions.

   (2)  The Department has not collected the taxes due under the other means set forth in sections 2806(g)(3)(iii) and 2809(c)(2).

 (b)  In addition to the affidavit required under subsection (a), the EDC shall file with the Commission:

   (1)  A statement of the amount of payments under section 2806(g) or 2809(c) for the immediately preceding 12-month period ending on June 30, plus interest accrued at 6% per year from the time of payment until the time the payments are reflected in customer rates, supported by a copy of the notification received from the Department assessing these taxes and related interest.

   (2)  A proof of revenue calculation by rate class demonstrating the impact of the proposed rate increase upon each class of customers. The dollar and percentage changes shall be shown for each tariffed rate.

   (3)  A description of the surcharge for recovering the increased tax liability.

   (4)  A statement that the surcharge becomes effective for service rendered beginning 60 days after the filing of tariffs or tariff supplements.

 (a)  Surcharge calculation. Every EDC subjected to new or increased State taxes under sections 2806(g), 2809(c) and 2810 of the code (relating to implementation, pilot programs and performance-based rates; requirements for electric generation suppliers; and revenue-neutral reconciliation) and § §  69.51—69.56 (relating to inclusion of State taxes and gross receipts taxes in base rates) that proposes to modify its STAS to recover these taxes shall include the following information in its surcharge calculation:

   (1)  The amounts paid under sections 2806(g) and 2809(c) for the immediately preceding 12-month period ending on June 30, plus interest accrued at 6% per year from the time of payment until the time the payments are reflected in customer rates. The EDC shall also provide an affidavit that it has not recovered these taxes under the other means in sections 2806(g)(3)(iii) and 2809(c)(2) of the code.

   (2)  Adjustments to the gross receipts tax rate pursuant to the RNR.

   (3)  When applicable, paragraphs (1) and (2) shall be added to any other amounts recoverable under the STAS.

   (4)  The total of paragraph (3) divided by a factor which is the complement of the Gross Receipts Tax (GRT) rate (1 minus the GRT rate), adjusted by the RNR to the extent that recovery is approved by the Commission under section 2804(16) of the code (relating to standards for restructuring of electric industry).

   (5)  The quotient of paragraph (4) divided by gross intrastate operating revenues derived from service under rates subject to the jurisdiction of the Commission for the most recently completed calendar year, exclusive of the revenues produced by the surcharge permitted by subsection (a). This quotient shall be expressed as a percentage.

   (2)  If the EDC increased or decreased its rates under the Commission’s jurisdiction during or after the most recently completed calendar year, it shall include in its computation the appropriate adjustments to paragraphs (1)—(5), as if the increased or decreased rates had been in effect for all of that calendar year.

 (b)  For rate changes that require the STAS to be filed under this section, every EDC shall provide the following information to the Commission:

   (1)  For a change in an EDC’s RNR tax liability contained in a notice from the Department, the information described in §  54.94(b)(3) (relating to recovery of changes in State tax liability).

   (2)  For amounts paid by an EDC under sections 2806(g) and 2809(c) of the code, the information described in §  54.94(b)(4).

 (a)  An EDC proposing to increase its rates under §  54.94 or §  54.96 (relating to recovery of changes in State tax liability; and recovery of sections 2806(g) and 2809(c) tax liability producing rates above the rate cap) shall provide customer notice as provided in §  53.45(g) (relating to public notice of new tariffs and tariff changes).

 (b)  An EDC proposing to increase its rates under §  54.95 (relating to recovery of RNR tax liability producing rates above the rate cap) shall provide customer notice and follow the tariff posting procedures in § §  53.41—53.45 (relating to posting of tariffs and notices).

Subchapter E. COMPETITIVE SAFEGUARDS

Sec.

 Electric generation suppliers and electric distribution companies shall comply with the following requirements:

   (1)  An electric distribution company may not give an electric generation supplier, including without limitation, its affiliate or division, any preference or advantage over any other electric generation supplier in processing a request by a distribution company customer for retail generation supply service.

   (2)  Subject to customer privacy or confidentiality constraints, an electric distribution company may not give an electric generation supplier, including without limitation its affiliate or division, any preference or advantage in the dissemination or disclosure of customer information and any dissemination or disclosure shall occur at the same time and in an equal and nondiscriminatory manner. ‘‘Customer information’’ means all information pertaining to retail electric customer identity and current and future retail electric customer usage patterns, including appliance usage patterns, service requirements or service facilities.

   (3)  An electric distribution company or electric generation supplier may not engage in false or deceptive advertising to customers with respect to the retail supply of electricity in this Commonwealth.

   (4)  Each electric distribution company shall adopt the following dispute resolution procedures to address alleged violations of this section:

     (i)   Regarding any dispute between an electric distribution company or a related supplier, or both, and an electric generation supplier (each individually referred to as a ‘‘party’’ and collectively referred to as ‘‘parties’’), alleging a violation of any of the provisions of this section, the electric generation supplier shall provide the electric distribution company or related supplier, or both, as applicable, a written notice of dispute which includes the names of the parties and customers, if any involved and a brief description of the matters in dispute.

     (ii)   Within 5 days of receipt of the notice by the electric distribution company or related supplier, or both, a designated senior representative of each of the parties shall attempt to resolve the dispute on an informal basis.

     (iii)   If the designated representatives are unable to resolve the dispute by mutual agreement within 30 days of the referral, the dispute shall be referred for mediation through the Commission’s Office of Administrative Law Judge. A party may request mediation prior to that time if it appears that informal resolution is not productive.

     (iv)   If mediation is not successful, the matter shall be converted to a formal proceeding before a Commission administrative law judge, and the prosecuting parties shall be directed to file a formal pleading in the nature of a complaint, petition or other appropriate pleading with the Commission within 30 days or the matter will be dismissed for lack of prosecution. Any party may file a complaint, petition or other appropriate pleading concerning the dispute under any relevant provision of 66 Pa.C.S. (relating to the Public Utility Code).

   (5)  An electric distribution company may not illegally tie the provision of any electric distribution service within the jurisdiction of the Commission to one of the following:

     (i)   The purchase, lease or use of any other goods or services offered by the electric distribution company or its affiliates.

     (ii)   A direct or indirect commitment not to deal with any competing electric generation supplier.

   (6)  An electric distribution company may not provide any preference or advantage to any electric generation supplier in the disclosure of information about operational status and availability of the distribution system.

   (7)  An electric distribution company shall supply all regulated services and apply tariffs to nonaffiliated electric generation suppliers in the same manner as it does for itself and its affiliated or division electric generation supplier, and shall uniformly supply all regulated services and apply its tariff provisions in a nondiscriminatory manner.

   (8)  Every electric distribution company and its affiliated or divisional electric generation supplier shall formally adopt and implement these provisions as company policy and shall take appropriate steps to train and instruct its employes in their content and application.

   (9)  If an electric distribution company customer requests information about electric generation suppliers, the electric distribution company shall provide the latest list as compiled by the Commission to the customer over the telephone, or in written form or by other equal and nondiscriminatory means. In addition, an electric distribution company may provide the address and telephone number of an electric generation supplier if specifically requested by the customer by name. To enable electric distribution companies to fulfill this obligation, the Commission will maintain a written list of licensed electric generation suppliers. The Commission will regularly update this list and provide the updates to electric distribution companies as soon as reasonably practicable. The Commission will compile the list in a manner that is fair to all electric generation suppliers and that is not designed to provide any particular electric generation supplier with a competitive advantage.

   (10)  An electric distribution company or its affiliate or division may not state or imply that any delivery services provided to an affiliate or division or customer of either are inherently superior, solely on the basis of their affiliation with the electric distribution company, to those provided to any other electric generation supplier or customer or that the electric distribution company’s delivery services are enhanced should supply services be procured from its affiliate or division. When an electric distribution company’s affiliated or divisional supplier markets or communicates to the public using the electric distribution company’s name or logo, it shall include a disclaimer stating that the affiliated or divisional supplier is not the same company as the electric distribution company, that the prices of the affiliated or divisional supplier are not regulated by the Commission and that a customer is not required to buy electricity or other products from the affiliated or divisional supplier to receive the same quality service from the electric distribution company. When an affiliated or divisional supplier advertises or communicates through radio, television or other electronic medium to the public using the electric distribution company’s name or logo, the affiliated or divisional supplier shall include at the conclusion of any communication a disclaimer that includes all of the disclaimers listed in this paragraph.

 The following standards apply to the transfer of a retail customer’s electric generation service from an EGS to a default service provider within the meaning of §  54.182 (relating to definitions):

   (1)  An EGS may not transfer a retail customer from its electric generation service to the default service provider without the consent of the default service provider, except in the following situations:

     (i)   Upon Commission approval of the abandonment, suspension or revocation of an EGS license, consistent with § §  54.41 and 54.42 (relating to transfer or abandonment of license; and license suspension; license revocation).

     (ii)   Upon nonpayment by a retail customer for services rendered by the EGS.

     (iii)   To correct an unauthorized or inadvertent switch of a retail customer’s account from default service to an alternative EGS’s service, consistent with §  57.177 (relating to customer dispute procedures).

     (iv)   Upon the normal expiration of contracts.

   (2)  An EGS may initiate transfers in the situations in paragraph (1) through standard electronic data interchange protocols.

   (3)  The Commission may impose a penalty for every retail customer transferred to default service in violation of this section, consistent with 66 Pa.C.S. § §  3301—3316 (relating to violations and penalties).

   The provisions of this §  54.123 adopted September 14, 2007, effective September 15, 2007, 37 Pa.B. 4996.

   This section cited in 52 Pa. Code §  54.186 (relating to default service procurement and implementation plans).

Subchapter F. REPORTING REQUIREMENTS FOR QUALITY OF SERVICE BENCHMARKS AND STANDARDS

Sec.

 The following words and terms, when used in this subchapter, have the following meanings, unless the context clearly indicates otherwise:

   BCS—The Bureau of Consumer Services of the Commission.

   Business office—A centralized service group which receives small commercial or residential billing inquiries, or both, and requests for service, whether or not equipped with an automated call distribution system.

   Busy-out rate—The number of calls to an EDC’s call center or business office that received a busy signal divided by the number of calls that were received.

   Call abandonment rate—The number of calls to an EDC’s call center or business office that were abandoned divided by the total number of calls received at the EDC’s telephone call center or business office.

   Call center—A centralized facility established by a utility for transactions concerning installation and repair of service, billing and other inquiries between residential and small commercial customers and EDC representatives, but not including special purpose call centers established to respond to service emergencies and operating for a temporary period of time.

   Code—The Public Utility Code, 66 Pa.C.S. § §  101—3316.

   Commission—The Pennsylvania Public Utility Commission.

   Customer—A retail electric customer as defined in section 2803 of the code (relating to definitions).

   EDC—Electric Distribution Company—The term defined in section 2803 of the code.

   Informal consumer complaint—An appeal by a consumer to the BCS about a utility’s proposed resolution of a dispute related to billing, service delivery, repairs and all other issues not related to requests for payment arrangements.

   Informally verified infraction—An apparent misapplication of Commission regulations as determined by the BCS through its examination of information obtained as part of its review of informal consumer complaints and payment arrangement requests:

     (i)   The informal verification process implemented by the BCS notifies a utility of the information which forms the basis of an alleged infraction, affords the utility the opportunity to affirm or deny the accuracy of the information, and concludes with a BCS determination regarding the alleged infraction.

 (a)  Reporting requirements.

   (1)  Unless otherwise specified in this subchapter, each EDC shall file its first report with the Commission on or before August 1, 1999. The August report shall contain data, reported by month, from the first 6 months of the calendar year, as well as a 6-month cumulative average.

   (2)  Each EDC shall file its second report on or before February 1, 2000. The February report shall contain data, reported by month, from the second 6 months of the year as well as 6-month cumulative average and a 12-month cumulative average for the preceding calendar year.

   (3)  Thereafter, the EDCs shall file reports annually with the Secretary of the Commission on or before February 1. Each report shall contain data, reported by month, as well as a 12-month cumulative average for the preceding calendar year. Each report shall include the name and telephone number of the utility contact person responsible for the report.

 (b)  Records. Each EDC shall take measures necessary and keep sufficient records to report the following data to the Commission:

   (1)  Telephone access.

     (i)   The percent of calls answered at each EDC’s call center or business office, or both, within 30 seconds with the EDC representative ready to render assistance and to accept information necessary to process the call. An acknowledgment that the customer or applicant is waiting on the line does not constitute an answer. If the EDC reports data for more than one call center or business office, the EDC should also provide the combined percent of calls answered within 30 seconds for the EDC as a whole.

     (ii)   The average busy-out rate for each call center business office, or both. If the EDC reports data for more than one call center or business office, the EDC should also provide the combined busy-out rate for the EDC as a whole.

     (iii)   The call abandonment rate for each call center or business office, or both. If the EDC reports data for more than one call center or business office, the EDC should also provide the combined call abandonment rate for the EDC as a whole.

   (2)  Billing.

     (i)   The number and percent of residential bills that the EDC failed to render once every billing period to residential ratepayers under §  56.11 (relating to billing frequency).

     (ii)   The number and percent of bills that the EDC failed to render once every billing period to small business customers.

   (3)  Meter reading.

     (i)   The number and percent of residential meters for which the company has failed to obtain an actual or ratepayer supplied reading within the past 6 months to verify the accuracy of estimated readings in accordance with §  56.12(4)(ii) (relating to meter reading; estimated billing; or ratepayer readings).

     (ii)   The number and percent of residential meters for which the company has failed to obtain an actual meter reading within the past 12 months to verify the accuracy of the readings, either estimated or ratepayer read in accordance with §  56.12(4)(iii).

     (iii)   The number and percent of residential remote meters for which it has failed to obtain an actual meter reading under the time frame in §  56.12(5)(ii).

   (4)  Response to disputes. The actual number of disputes as described in Chapter 56, Subchapter F (relating to disputes; termination disputes; informal and formal complaints) for which the company did not provide a response to the complaining party within 30 days of the initiation of the dispute under §  56.151(5) (relating to general rule).

 (a)  Results of telephone transaction surveys. Each EDC shall report to the Commission the results of telephone transaction surveys of customers who have had interactions with the EDC.

   (1)  The purpose of the transaction surveys is to assess the customer perception regarding the most recent interaction with the EDC. Survey questions shall measure access to the utility, employe courtesy, employe knowledge, promptness of EDC response or visit, timeliness of EDC response or visit and satisfaction with the handling of the interaction.

   (2)  The transaction survey questions shall specifically address the circumstances that generated the most recent transaction. Interaction categories include the following:

     (i)   Service installation.

     (ii)   Premise visit by company field personnel for an activity other than service installation.

     (iii)   Service interruption.

     (iv)   Billing balance inquiry or dispute.

     (v)   Request for discontinuance of service.

     (vi)   Application for service.

     (vii)   Other similar interactions.

   (3)  The EDCs shall carry out the transaction survey process using instruments and procedures that provide the Commission with uniform data that can be used to directly compare customer service performance among EDCs in this Commonwealth.

   (4)  A customer or consumer being surveyed shall be contacted within 30 days of the date that the interaction with the EDC took place.

   (5)  The sampling plan shall be designed so that the results are statistically valid within plus or minus 5%.

 (b)  Commission approval. The survey instrumentation, as well as procedures for case selection, sampling, conducting the survey, analyzing results and reporting to the Commission shall be subject to the review and approval of the Commission.

 (c)  Timetable.

   (1)  The first report on survey results shall be submitted to the Commission on or before October 1, 2000. The October report shall contain survey results, reported by month, from the first 6 months of the calendar year.

   (2)  The second report shall be submitted on or before April 1, 2001. The April report shall contain results, reported by month, from the second 6 months of the previous year as well as cumulative 12-month results.

 (a)  The BCS will review and analyze residential informal consumer complaints and payment arrangement requests filed with the Commission and will report the justified consumer complaint rate and the justified payment arrangement request rate to the Commission on an annual basis.

 The Commission will annually produce a summary report on the customer service performance of each EDC using the statistics collected as a result of these reporting requirements. The reports will be public information. The Commission will provide the reports to any interested party and post the reports on the Commission’s Internet website.

Subchapter G. DEFAULT SERVICE

Sec.

 The following words and terms, when used in this subchapter, 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).

   Commission—The Pennsylvania Public Utility Commission.

   Competitive bid solicitation process—A fair, transparent and nondiscriminatory process by which a default service provider 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 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 energy purchases, technical requirements and related forms and agreements.

   Default service procurement plan—The electric generation supply acquisition strategy a DSP will use 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 a DSP that identifies a procurement plan, an implementation plan, a rate design to recover all reasonable costs and other elements identified in §  54.185 (relating to default service programs and periods of service).

   Default service rate—The rate billed to a default service customer resulting from compliance with a Commission approved default service program.

   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.

   FERC—The Federal Energy Regulatory Commission.

   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 price—The price that is available in the wholesale market at particular points in time for electric generation supply.

   RTO—Regional transmission organization—A 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.

 (a)  The DSP shall be the incumbent EDC in each certificated service territory, except as provided for under subsection (b).

 (b)  The DSP may be changed by one of the following processes:

   (1)  An EDC may petition the Commission to be relieved of the default service obligation.

   (2)  An EGS may petition the Commission to be assigned the default service role for a particular EDC service territory.

   (3)  The Commission may propose through its own motion that an EDC be relieved of the default service obligation.

 (c)  The Commission may reassign the default service obligation for the entire service territory, or for specific customer classes, to one or more alternative DSPs when it finds it to be necessary for the accommodation, safety and convenience of the public. A finding would include an evaluation of the incumbent EDC’s operational and financial fitness to serve retail customers, and its ability to provide default service under reasonable rates and conditions. In these circumstances, the Commission will announce, through an order, a competitive process to determine the alternative DSP.

 (d)  When the Commission finds that an EDC should be relieved of the default service obligation, the competitive process for the replacement of the default service provider shall be as follows:

   (1)  An entity that wishes to be considered for the role of the alternative DSP shall file a petition under 66 Pa.C.S. §  2807(e)(3) (relating to duties of electric distribution companies).

   (2)  Petitioners shall demonstrate their operational and financial fitness to serve and their ability to comply with Commission regulations, orders and applicable laws pertaining to public utility service.

   (3)  If no petitioner can meet this standard, the incumbent EDC shall be required to continue the provision of default service.

   (4)  If one or more petitioners meets the standard provided in paragraph (2), the Commission will approve the DSP best able to fulfill the obligation in a safe, cost-effective and efficient manner, consistent with 66 Pa.C.S. § §  1103 and 1501 (relating to procedure to obtain certificates of public convenience; and character of service and facilities) and 2807(e).

 (a)  A DSP shall be responsible for the reliable provision of default service to retail customers who are not receiving generation services from an alternative EGS within the certificated territory of the EDC that it serves or whose alternative EGS has failed to deliver electric energy.

 (b)  A DSP shall comply with the code and Chapter 1 (relating to rules of administrative practice and procedure) to the extent that the obligations are not modified by this subchapter or waived under §  5.43 (relating to petitions for issuance, amendment, repeal or waiver of regulations).

 (a)  A DSP shall file a default service program with the Commission’s Secretary’s Bureau no later than 12 months prior to the conclusion of the currently effective default service program or Commission-approved generation rate cap for that particular EDC service territory, unless the Commission authorizes another filing date. Thereafter, the DSP shall file its programs consistent with schedules identified by the Commission.

 (b)  Default service programs must comply with Commission regulations pertaining to documentary filings in Chapter 1 (relating to rules of administrative practice and procedure), except when modified by this subchapter. The DSP shall serve copies of the default service program on the Pennsylvania Office of Consumer Advocate, Pennsylvania Office of Small Business Advocate, the Commission’s Office of Trial Staff, EGSs registered in the service territory and the RTO or other entity in whose control area the DSP is operating. Copies shall be provided upon request to other EGSs and shall be available at the DSP’s public internet domain.

 (c)  The first default service program shall be for a period of 2 to 3 years, or for a period necessary to comply with subsection (d)(4), unless another period is authorized by the Commission. Subsequent program terms will be determined by the Commission.

 (d)  A default service program must include the following elements:

   (1)  A procurement plan identifying the DSP’s electric generation supply acquisition strategy for the period of service. The procurement plan should identify the means of satisfying the minimum portfolio requirements of the Alternative Energy Portfolio Standards Act (73 P. S. § §  1648.1—1648.8) for the period of service.

   (2)  An implementation plan identifying the schedules and technical requirements of competitive bid solicitations and spot market energy purchases, consistent with §  54.186 (relating to default service procurement and implementation plans).

   (3)  A rate design plan recovering all reasonable costs of default service, including a schedule of rates, rules and conditions of default service in the form of proposed revisions to its tariff.

   (4)  Documentation that the program is consistent with the legal and technical requirements pertaining to the generation, sale and transmission of electricity of the RTO or other entity in whose control area the DSP is providing service. The default service procurement plan’s period of service must align with the planning period of that RTO or other entity.

   (5)  Contingency plans to ensure the reliable provision of default service when a wholesale generation supplier fails to meet its contractual obligations.

   (6)  Copies of agreements or forms to be used in the procurement of electric generation supply for default service customers. This includes all documents used as part of the implementation plan, including supplier master agreements, request for proposal documents, credit documents and confidentiality agreements. When applicable, the default service provider shall use standardized forms and agreements that have been approved by the Commission.

   (7)  A schedule identifying generation contracts of greater than 2 years in effect between a DSP, when it is the incumbent EDC, and retail customers in that service territory. The schedule should identify the load size and end date of the contracts. The schedule shall only be provided to the Commission and will be treated as confidential.

 (e)  The Commission may, following notice and opportunity to be heard, direct that some or all DSPs file joint default service programs to acquire electric generation supply for all of their default service customers. In the absence of such a directive, some or all DSPs may jointly file default service programs or coordinate the scheduling of competitive bid solicitations to acquire electric generation for all of their default service customers. A multiservice territory procurement and implementation plan must comply with §  54.186.

 (f)  DSPs shall include requests for waivers from the provisions of this subchapter in their default service program filings. For DSPs with less than 50,000 retail customers, the Commission will grant waivers to the extent necessary to reduce the regulatory, financial or technical burden on the DSP or to the extent otherwise in the public interest.

 (a)  A DSP shall acquire electric generation supply at prevailing market prices for default service customers in a manner consistent with procurement and implementation plans approved by the Commission.

 (b)  A DSP’s procurement plan must adhere to the following standards:

   (1)  The procurement plan shall be designed to acquire electric generation supply at prevailing market prices to meet the DSP’s anticipated default service obligation at reasonable costs.

   (2)  DSPs with loads of 50 mW or less shall evaluate the cost and benefits of joining with other DSPs or affiliates in contracting for electric supply.

   (3)  Procurement plans may include solicitations and contracts whose duration extends beyond the program period.

   (4)  Electric generation supply shall be acquired by competitive bid solicitation processes, spot market energy purchases or a combination of both.

   (5)  The DSP’s supplier affiliate may participate in a competitive bid solicitation process used as part of the procurement plan subject to the following conditions:

     (i)   The DSP shall propose and implement protocols to ensure that its supplier affiliate does not receive an advantage in the solicitation and evaluation of competitive bids, or other aspect of the implementation plan.

     (ii)   The competitive bid solicitation process shall comply with the codes of conduct promulgated by the Commission in §  54.122 (relating to code of conduct).

 (c)  A DSP’s implementation plan must adhere to the following standards:

   (1)  A competitive bid solicitation process used as part of the default service implementation plan must provide, to the extent applicable and at the appropriate time, the following information to suppliers:

     (i)   A bidding schedule.

     (ii)   A definition and description of the power supply products on which potential suppliers shall bid.

     (iii)   Bid price formats.

     (iv)   A time period during which the power will need to be supplied for each power supply product.

     (v)   Bid submission instructions and format.

     (vi)   Price-determinative bid evaluation criteria.

     (vii)   Current load data for rate schedules or maximum registered peak load groupings, including the following:

       (A)   Hourly usage data.

       (B)   Number of retail customers.

       (C)   Capacity peak load contribution figures.

       (D)   Historical monthly retention figures.

       (E)   Estimated loss factors.

       (F)   Customer size distribution.

   (2)  The default service implementation plan must include fair and nondiscriminatory bidder qualification requirements, including financial and operational qualifications, or other reasonable assurances of a supplier of electric generation services’ ability to perform.

   (3)  A competitive bid solicitation process used as part of the implementation plan will be subject to monitoring by the Commission or an independent third party evaluator selected by the DSP in consultation with the Commission. A third party evaluator shall operate at the direction of the Commission. Commission staff and a third party evaluator involved in monitoring the procurement process shall have full access to all information pertaining to the competitive procurement process, either remotely or where the process is administered. A third party evaluator retained for purposes of monitoring the competitive procurement process shall be subject to confidentiality agreements identified in §  54.185(d)(6) (relating to default service programs and periods of service).

   (4)  The DSP or third party evaluator shall review and select winning bids procured through a competitive bid solicitation process in a nondiscriminatory manner based on the price determinative bid evaluation criteria set forth consistent with paragraph (1)(vi).

   (5)  The bids submitted by a supplier in response to a competitive bid solicitation process shall be treated as confidential pursuant to the confidentiality agreement approved by the Commission under §  54.185(d)(6). The DSP, the Commission and a third party involved in the administration, review or monitoring of the bid solicitation process shall be subject to this confidentiality provision.

 (d)  The DSP may petition for modifications to the approved procurement and implementation plans when material changes in wholesale energy markets occur to ensure the acquisition of sufficient supply at prevailing market prices. The DSP shall monitor changes in wholesale energy markets to ensure that its procurement plan continues to reflect the incurrence of reasonable costs, consistent with 66 Pa.C.S. §  2807(e)(3) (relating to duties of electric distribution companies).

 (a)  The costs incurred for providing default service shall be recovered through a default service rate schedule. The rate schedule shall be designed to recover fully all reasonable costs incurred by the DSP during the period default service is provided to customers, based on the average cost to acquire supply for each customer class.

 (b)  Except for rates available consistent with subsection (f), a default service customer shall be offered a single rate option, which shall be identified as the PTC and displayed as a separate line item on a customer’s monthly bill.

 (c)  The rates charged for default service may not decline with the increase in kilowatt hours of electricity used by a default service customer in a billing period.

 (d)  The PTC shall be designed to recover all default service costs, including generation, transmission and other default service cost elements, incurred in serving the average member of a customer class. An EDC’s default service costs may not be recovered through the distribution rate. Costs currently recovered through the distribution rate, which are reallocated to the default service rate, may not be recovered through the distribution rate. The distribution rate shall be reduced to reflect costs reallocated to the default service rate.

 (e)  A DSP shall use an automatic energy adjustment clause, consistent with 66 Pa.C.S. §  1307 (relating to sliding scale of rates; adjustments) and Chapter 75 (relating to alternate energy portfolio standards), to recover all reasonable costs incurred through compliance with the Alternative Energy Portfolio Standards Act (73 P. S. § §  1648.1—1648.8). The use of an automatic adjustment clause shall be subject to audit and annual review, consistent with 66 Pa.C.S. §  1307(d) and (e), regarding fuel cost adjustment audits and automatic adjustment reports and proceedings.

 (f)  A DSP may use an automatic energy adjustment clause to recover reasonable nonalternative energy default service costs. The use of an automatic adjustment clause shall be subject to audit and annual review, consistent with 66 Pa.C.S. §  1307(d) and (e). A DSP may collect interest from retail customers on the recoveries of under collection of default service costs at the legal rate of interest. Refunds to customers for over recoveries shall be made with interest, at the legal rate of interest plus 2%.

 (g)  The default service rate schedule must include rates that correspond to demand side response and demand side management programs, as defined in section 2 of the Alternative Energy Portfolio Standards Act (73 P. S. §  1648.2), when the Commission mandates these rates pursuant to its authority under 66 Pa.C.S. Chapter 1 (relating to general provisions).

 (h)  Default service rates shall be adjusted on a quarterly basis, or more frequently, for all customer classes with a maximum registered peak load up to 25 kW, to ensure the recovery of costs reasonably incurred in acquiring electricity at prevailing market prices and to reflect the seasonal cost of electricity. DSPs may propose alternative divisions of customers by maximum registered peak load to preserve existing customer classes.

 (i)  Default service rates shall be adjusted on a quarterly basis, or more frequently, for all customer classes with a maximum registered peak load of 25 kW to 500 kW, to ensure the recovery of costs reasonably incurred in acquiring electricity at prevailing market prices and to reflect the seasonal cost of electricity. DSPs may propose alternative divisions of customers by maximum registered peak load to preserve existing customer classes.

 (j)  Default service rates shall be adjusted on a monthly basis, or more frequently, for all customer classes with a registered peak load of equal to or greater than 500 kW to ensure the recovery of costs reasonably incurred in acquiring electricity at prevailing market prices and to reflect the seasonal cost of electricity. DSPs may propose alternative divisions of customers by registered peak load to preserve existing customer classes.

 (k)  When a supplier fails to deliver electric generation supply to a DSP, the DSP shall be responsible for acquiring replacement electric generation supply consistent with its Commission-approved contingency plan. When necessary to procure electric generation supply before the implementation of a contingency plan, a DSP shall acquire supply at prevailing market prices and fully recover all reasonable costs associated with this activity that are not otherwise recovered through its contract terms with the default supplier. The DSP shall follow acquisition strategies that reflect the incurrence of reasonable costs, consistent with 66 Pa.C.S. §  2807(e)(3) (relating to duties of electric distribution companies), when selecting from the various options available in these energy markets.

 (a)  A default service program will initially be referred to the Office of Administrative Law Judge for further proceedings as may be required.

 (b)  The Commission will issue an order within 7 months of a program’s filing with the Commission on whether the default service program demonstrates compliance with this subchapter and 66 Pa.C.S. § §  2801—2812 (relating to the Electricity Generation Customer Choice and Competition Act).

 (c)  Upon entry of the Commission’s final order, a DSP shall acquire generation supply for the period of service in a manner consistent with the terms of the approved procurement and implementation plans and consistent with the standards identified in §  54.186 (relating to default service procurement and implementation plans).

 (d)  Upon receiving written notice, the Commission will have 1 business day, to approve or disapprove the results of a competitive bid solicitation process used by a DSP as part of its procurement plan. When the Commission does not act within 1 business day the results of the process will be deemed approved. The Commission will not certify or otherwise approve or disapprove a DSP’s spot market energy purchases made pursuant to a Commission-approved procurement plan. The Commission will monitor the DSP’s adherence to the terms of the approved default service program and 66 Pa.C.S. § §  2801—2812 (relating to the Electricity Generation Customer Choice and Competition Act). The Commission may initiate an investigation regarding implementation of the DSP’s default service program and, at the conclusion of the investigation, order remedies as may be lawful and appropriate. the Commission will not deny the DSP the recovery of its reasonable costs for purchases made pursuant to an approved competitive procurement process unless the DSP concealed or misled the Commission regarding its adherence to the program, or otherwise violated the provisions of this subchapter or the code.

 (e)  A DSP shall adhere to the following procedures in obtaining approval of default service rates and providing notice to default service customers:

   (1)  A DSP shall provide all customers notice of the filing of a default service program in a similar manner as found in §  53.68 (relating to notice requirements).

   (2)  A DSP shall provide all customers notice of the initial default service rates and terms and conditions of service 60 days before their effective date, or 30 days after bidding has concluded, whichever is sooner, unless another time period is approved by the Commission. The DSP shall provide written notice to the named parties identified in §  54.185(b) (relating to default service programs and periods of service) containing an explanation of the methodology used to calculate the price for electric service.

   (3)  After the initial steps of a default service procurement and implementation plan are completed, the DSP shall file with the Commission tariff supplements designed to reflect, for each customer class, the rates to be charged for default service. The tariff supplements shall be accompanied by supporting documentation adequate to demonstrate adherence to the procurement plan approved by the Commission, the procurement plan results and the translation of those results into customer rates.

   (4)  A customer or party identified in §  54.185(b) may file exceptions to the initial default service tariffs within 20 days of the date the tariffs are filed with the Commission. The exceptions shall be limited to whether the DSP properly implemented the procurement plan approved by the Commission and accurately calculated the rates. The Commission will resolve filed exceptions by order. The Commission may allow the default rates to become effective pending the resolution of those exceptions.

 (a)  At the conclusion of an EDC’s Commission approved generation rate cap, retail customers who are not receiving generation service from an EGS shall be assigned to the Commission-approved DSP in that service territory.

 (b)  A DSP shall accept applications for default service from new retail customers when the customers comply with Commission regulations pertaining to applications for service, including those in Chapter 56 (relating to standards and billing practices for residential utility service) and accept all retail customers assigned to its default service who switch from an EGS.

 (c)  A DSP shall treat a customer who leaves an EGS as it would a new applicant for default service.

 (d)  A default service customer may choose to receive its generation service from an EGS at any time, if the customer complies with all Commission regulations pertaining to changing generation service providers in Chapter 57 (relating to electric service).

 (e)  A DSP may not charge a fee to a retail customer for changing its generation service provider in a manner consistent with Commission regulations.

Subchapter H. RETAIL ELECTRICITY CHOICE SALES ACTIVITY REPORTS

Sec.

 (a) Reporting requirements.

   (1)  An EDC or an active EGS shall report the information regarding retail sales of electric generation in accordance with this subchapter.

   (2)  An EDC shall report retail sales activity in its service territory. The EDC shall report information by customer class for residential, commercial, and industrial customers. An EDC with capped electric generation rates shall report information in the aggregate for residential customers, and by rate schedule and in the aggregate for commercial and industrial customers. An EDC that does not have capped electric generation rates shall report information for residential, commercial and industrial customers by rate class as defined by the default service program approved by the Commission. The EDC shall report the following information:

     (i)   Total number of customer accounts served by EGSs.

     (ii)   Total number of customer accounts being served by EGSs and the EDC.

     (iii)   MWh sales of EGSs.

     (iv)   MWh sales of EGSs and the EDC.

     (v)   EGSs serving customer accounts by class.

     (vi)   Total number of EDC TOU customer accounts served by EGSs.

     (vii)   Total number of EDC TOU customer accounts served by EGSs and the EDC.

     (viii)   MWh sales of EGSs to EDC TOU customer accounts.

     (ix)   MWh sales of EGSs and the EDC to EDC TOU customer accounts.

     (x)   Total number of EDC hourly/real time price customer accounts served by EGSs.

     (xi)   Total number of hourly/real time price customer accounts served by EGSs and the EDC.

     (xii)   MWh sales by EGSs to EDC hourly/real time priced customer accounts.

     (xiii)   MWh sales by EGSs and the EDC to EDC hourly/real time priced customer accounts.

   (3)  An EDC shall report retail sales activity of EGSs operating in its service territory. An EDC shall report the following information for an EGS providing service in the EDC’s service territory, marking the information as confidential:

     (i)   Identity of the EGS.

     (ii)   Number of customer accounts served by the EGS by customer class for residential, commercial and industrial customers.

     (iii)   Sales in MWh of customer accounts served by the EGS by customer class for residential, commercial and industrial customers.

   (4)  An active EGS shall report retail sales activity on a Statewide basis. The EGS shall report the following information by customer class for residential, small nonresidential customers, medium nonresidential customers and large nonresidential customers, marking the information as confidential:

     (i)   Number of customer accounts.

     (ii)   Number of flat rate customer accounts.

     (iii)   Number of seasonal rate customer accounts.

     (iv)   Number of TOU customer accounts.

     (v)   Number of hybrid rate customer accounts.

     (vi)   Number of fixed term contract customer accounts by length of the original primary contract, specifying the length in number of years.

     (vii)   Number of green power customer accounts.

     (viii)   Number of mandatory curtailable customer accounts.

     (ix)   Number of voluntary curtailable customer accounts.

     (x)   Number of customer accounts based on billing methods.

     (xi)   Number of hourly/real time pricing customer accounts.

   (5)  An EDC shall file quarterly sales activity reports with the Commission’s Secretary and CEEP. A quarterly report shall be filed no later than 30 days after the end of the previous quarter.

   (6)  An active EGS shall file an annual sales activity report for the previous calendar year with the Commission’s Secretary and CEEP on or before April 30 of each year.

 (b) Report forms.

   (1)  The Commission shall provide separate report forms for EDC and EGS use. An EDC or an active EGS shall use the applicable report form.

   (2)  Report forms shall be made available in both paper and electronic format. Report forms in electronic format may be downloaded at the Commission’s web site, or will be provided in paper format upon request to the Commission’s forms officer.

   (3)  An EDC or active EGS shall file an original and two copies of a completed paper report form with the Commission’s Secretary and CEEP. When the report form is filed electronically, one paper copy of the report form shall be filed with the Commission’s Secretary no later than 15 days after the report is due.

 The Commission will make available to the public on an aggregated basis information contained in sales activity reports that does not disclose individual EGS market shares.