§ 69.1. General.

 (a)  Since 66 Pa.C.S. §  1307 (relating to sliding scale of rates; adjustments), enables a utility to pass fuel costs directly to the ratepayers, a utility has the highest degree of responsibility to take aggressive action on behalf of its ratepayers to control fuel costs. A utility should use every means reasonably available to monitor and enforce vendor adherence to all aspects of fuel procurement agreements. In addition to contract adherence, the Commission may exercise its independent right to review whether each utility purchases the lowest cost fuel that meets the necessary standards and specifications, which may include a review to determine if the utility is continually, thoroughly and aggressively searching the fuel market for reasonably priced fuel. The Commission may make constructive suggestions with regard to an individual company’s fuel procurement policies and procedures from time to time.

 (b)  The purpose of § §  69.1—69.2, 69.4 and 69.5 (relating to fuel procurement policies and procedures) is to establish guidelines that the Commission recommends an electric utility follow in its fuel procurement activities. The Commission realizes that fuel procurement practices of utilities may differ depending on individual circumstances. However, the Commission believes that there are certain common procedures that will result in the lowest reasonable fuel costs. The Commission defines lowest reasonable cost to be fuel purchases that result in the lowest generating costs. This fuel should be consistent with contracted quality, regulatory requirements and prevailing wage rates, and may or may not be the lowest priced fuel.

 (c)  If a utility believes that an otherwise nonconforming fuel procurement policy will, in the long term, result in lower costs, the utility should submit the details of the policy for review by the Commission prior to implementation.

 (d)  If it appears, through Commission review, that nonconforming fuel procurement practices have resulted in excessive fuel costs, a utility may be required to demonstrate the reasonableness of the costs.

 (e)  If the Commission determines after notice and hearing that a utility’s nonconforming fuel procurement policy has resulted in unreasonable fuel costs, the utility shall be required to apply credits against the applicable energy cost rate or to make refunds to its customers.

 (f)  In order for the Commission to monitor fuel costs properly, a utility should record fuel prices FOB supplier with transportation costs reported separately. For contracts which state only delivered costs, the company should impute transportation costs and report those costs separately.

 (g)  Sections 69.1—69.2, 69.4 and 69.5 represent the standard by which the Commission intends to assess a utility’s fuel purchasing policies and procedures. Sections 69.1—69.2, 69.4 and 69.5 serve as notice to electric utilities of the Commission’s expectations with regard to fuel procurement policies and procedures. Utilities should apply § §  69.1—69.2, 69.4 and 69.5 prospectively in planning fuel purchases. Where provisions of existing contracts are in conflict with § §  69.1—69.2, 69.4 and 69.5, utilities need not seek to immediately amend the contracts, but should move towards the policies set forth in § §  69.1—69.2, 69.4 and 69.5 as contracts are modified, renegotiated or extended.

   The provisions of this §  69.1 issued under Public Utility Code,66 Pa.C.S. § §  501, 1301 and 1307.

 (a)  A utility should maintain an appropriate staff to adequately fulfill its responsibility to procure fuel at the lowest reasonable cost. The utility should be prepared to solicit and handle numerous competent bids and investigate these potential sources for ability to fulfill contracts.

 (b)  A utility should have a detailed organization chart of the personnel involved in fuel procurement, with a key official designated to act as liaison with the Commission. A utility should maintain written job descriptions for personnel, as well as formal policies and procedures pertaining to the fuel procurement process.

 (c)  Utility personnel in a position to influence fuel procurement decisions should be prohibited from having either direct or indirect ties or affiliations with fuel suppliers. A utility should conduct investigations to insure that personnel have no affiliation.

   The provisions of this §  69.1a issued under Public Utility Code,66 Pa.C.S. § §  501, 1301 and 1307.

   The provisions of this §  69.1a adopted October 18, 1985, effective October 19, 1985, 15 Pa.B. 3730.

 (a)  A utility should submit to the Commission its long-term generation plans and a statement of how the plans affect fuel purchasing policy and planning. A plan should be submitted each time there are revisions. A utility should adopt fuel purchasing strategies that provide lowest reasonable cost with maximum flexibility. It should strive to stimulate competition by purchasing from numerous suppliers.

 (b)  [Reserved].

   The provisions of this §  69.2 issued under Public Utility Code,66 Pa.C.S. § §  501, 1301 and 1307.

   The provisions of this §  69.2 amended October 18, 1985, effective October 19, 1985, 15 Pa.B. 3730. Immediately preceding text appears at serial pages (33013) to (33014).

 (a)  General. The Commission recommends that a utility adopt the following general purchasing guidelines:

   (1)  A balance of long-term, short-term and spot purchases should be utilized. This balance should provide a reasonably stable supply while allowing the utility the option of taking advantage of changing market conditions. At coal receiving sites, such as generating stations, central storage or loading facilities supplied by truck, coal handling equipment and procedures should be designed to accommodate numerous suppliers.

   (2)  Vendors should be selected on the basis of overall price and quality specifications of fuel that include, but are not limited to, Btu, moisture, ash and sulphur content. Service reliability is also a consideration. However, a utility is encouraged to give new suppliers every opportunity to compete, particularly in short-term/small-quantity fuel purchases. Documented service reliability becomes more important as contracts increase in duration and quantity. A utility should use its own staff in seeking and procuring adequate fuel supplies and should minimize the use of brokers, except where the use of brokers is consistent with the basic fuel procurement policy of obtaining fuel at the lowest reasonable price.

   (3)  Fuel agreements should include bonus/penalty provisions or be priced according to Btu, moisture, ash and sulphur content to insure that quality provisions are met. A utility should clearly state in fuel agreements the quality specifications of the fuel. Rejection limits for sulphur, ash and moisture content should be incorporated into contract or bid proposals.

   (4)  Fuel shipments should be adequately sampled when received at the generating plant. Contracts should include sampling procedures providing for an additional sealed and dated sample for independent verification if necessary.

   (5)  [Reserved].

   (6)  [Reserved].

   (7)  A utility should maintain documentation of reasons for rejection of bids on file in accordance with FERC’s Record Retention Table. During audits, Commission staff will inspect this documentation as deemed necessary.

   (8)  A utility should actively seek and maintain a significant number of vendors from which to solicit bids. This vendor list should be frequently updated with advertisements in newspapers and coal and oil publications.

 (b)  Short-term agreements and spot purchasing.

   (1)  [Reserved].

   (2)  Sealed bids should be considered on large orders covering more than 6 months’ supply.

   (3)  Verbal agreements, including telephone conversations relating to fuel price, quantity and quality, should be formalized by letter or a log confirming details. In securing vendors for inclusion on the vendor list referred to in subsection (a)(8), a utility should omit unnecessary provisions and requirements which restrict or discourage small suppliers from submitting bids. Requirements include engineering, geological and financial studies and reports which are not necessary for small, short-term or spot purchases.

   (4)  [Reserved].

   (5)  [Reserved].

 (c)  Long-term contracts.

   (1)  [Reserved].

   (2)  Cost escalation clauses included in long-term contracts should be based on measurable supplier costs, such as labor, material, transportation and equipment costs, and the like. Escalation clauses may also be based on regularly published relevant indices, such as those published by the United States Department of Interior, Bureau of Mines, the United States Department of Labor, and the like.

   (3)  Right to audit clauses should be included in contracts that provide for cost escalation. The right to audit clause gives the utility the authority to audit specific records of its suppliers. It is recommended that the utility enforce the right to audit provisions either through the use of qualified internal audit staff or outside independent auditors on a regular basis. Contracts should contain resumption clauses to provide for continuation (at the utility’s discretion) of contracts that are temporarily curtailed due to strikes or similar occurrences.

   (4)  It is recommended that all contracts, escalation clauses, or terms of purchase of fuel agreements be reviewed by the legal office of the utility. Contracts should include specific reference to special arrangements, such as loan agreements, which may affect the operation of the utility or the price of fuel.

   (5)  [Reserved].

   (6)  Minimum tonnage requirements should not be set at unreasonably high quantity levels which would prohibit competitive proposals from reliable and competent small suppliers. Investigations should be conducted to insure that potential vendors have adequate owned or contracted supplies to fulfill all contract provisions.

   (7)  A utility should seek contracts with greater ranges in minimum/maximum tonnage requirements to be exercised at the utility’s discretion. Contract tonnage would increase or decrease based on market conditions. The contracts would also provide a means of control over suppliers with excessive price or inferior quality.

   (8)  Escalation clauses based on market prices are discouraged. Market escalators, if used, should have a reasonable geographic limitation, yet should be sufficiently broadly based so that no supplier or group of suppliers could materially influence the market price. De-escalation should also be incorporated in the contracts based on the same market data. Data used to calculate the increment or decrement in coal prices should be based on comparable fuels and should not be influenced by short-term aberrations in coal prices. When incorporating market price escalators/de-escalators, the utility should delineate in the contract the comparable market data to be used and the time frames for adjustments. The Commission will review the reasonableness of market priced data on a case-by-case basis.

 (d)  Dedicated fuel supplies. Dedicated fuel supplies are those in which a utility, through ownership, contract tonnage requirements, location, or guarantee of debt, has substantial influence and interest in the contracted fuel supply. The following guidelines are recommended for dedicated fuel supplies and are in addition to the general and long-term contract guidelines in subsections (a) and (c):

   (1)  In order to insure efficient management over dedicated fuel supply, a utility should not provide, assume or guarantee an excessive amount of the project financing. The owner, operator or developer of the mine, or fuel supplier, should maintain substantial equity in the project or guarantee a substantial portion of the project financing.

   (2)  The use of cost-plus contracts is strongly discouraged.

   (3)  Contracts for dedicated fuel supplies should contain additional provisions so that if fuel prices exceed an average range of prices for fuel with similar characteristics for an extended period of time, the fuel price charged by the dedicated supplier would be adjusted to fall within the price range of the similar fuel. Under certain circumstances, similarities in methods of producing the fuel, contract provisions and geographic areas may also be considered. As with market-adjusted long-term contracts, the utility should establish and monitor the comparable market data that is to be utilized.

 (e)  Wholly-owned fuel sources. The following guidelines are in addition to the general, long-term contract, and dedicated fuel supply guidelines in subsections (a), (c) and (d):

   (1)  A utility should regularly compare the costs of fuel from its wholly-owned sources to that available in the competitive market place for fuel with similar characteristics. The Commission may take appropriate action when wholly-owned fuel costs differ significantly from comparable market prices for an extended period. A utility may be called upon to explain why its coal prices should not be reduced to the comparable market price. Decisions on a long-term deviation from market prices will be made by the Commission on a case-by-case basis.

   (2)  A utility should retain independent auditors to verify the charges affecting wholly-owned fuel costs. The Commission may review the audit of the fuel subsidiary or division and conduct reexaminations considered necessary.

   The provisions of this §  69.4 issued under Public Utility Code,66 Pa.C.S. § §  501, 1301 and 1307.

   The provisions of this §  69.4 amended October 18, 1985, effective October 19, 1985, 15 Pa.B. 3730. Immediately preceding text appears at serial pages (33014) to (33016).

 (a)  Since transportation costs often are a significant part of the cost of fuel, and are ultimately passed on to the consumer, the goal of the utility should be to provide reliable, timely transportation at a reasonable cost to the plant facility.

 (b)  A utility should maintain proper documentation and submit the information to the Commission upon request to insure that:

   (1)  Effective methods are used to schedule and control individual shipments of fuel.

   (2)  Transportation means available to insure the necessary service levels of reliability.

   (3)  Responsibility for negotiation of transportation costs is placed upon the appropriate persons who actively participate in the fuel procurement policies.

   (4)  Sufficient lead times are planned to permit delivery of fuels on a timely basis.

   (5)  Transportation costs are held to a minimum, considering reliability and quality of service.

   The provisions of this §  69.5 issued under Public Utility Code,66 Pa.C.S. § §  501, 1301 and 1307.

   The provisions of this §  69.5 amended October 18, 1985, effective October 19, 1985, 15 Pa.B. 3730. Immediately preceding text appears at serial page (33017).

   The provisions of this §  69.7 reserved October 18, 1985, effective October 19, 1985, 15 Pa.B. 3730. Immediately preceding text appears at serial pages (33017) to (33018).

SAFETY AND RELIABILITY GUIDELINES

 (a)  NGSs should deliver natural gas supplies under the terms of service specified in NGDC tariffs. Failure to deliver natural gas supplies in accordance with the tariffs may subject NGSs to penalties under procedures specified in the tariffs or revocation of licenses, or both. (See section 2203(12) of the act (relating to standards for restructuring of natural gas utility industry).) The NGSs may serve customers with different quality of service requirements, as permitted under the act and applicable NGDC tariffs.

 (b)  NGSs should utilize firm capacity sufficient to meet the requirements of their firm service customers except to the extent otherwise provided in each NGDC’s reliability plan. Service to any essential human needs retail gas customer lacking installed and operable alternative fuel capability and any residential retail gas customer should be firm service.

 (c)  NGSs should warrant to the NGDC that they have sufficient firm capacity to meet the requirements of the essential human needs retail gas customers, as defined in §  69.11 (relating to definitions), and should describe the characteristics of any firm capacity to the NGDC. The NGDC should take commercially reasonable steps to attempt to verify that the firm capacity contract rights exist. The failure or inability of an NGDC to verify the existence of the contract rights using commercially reasonable steps does not relieve an NGS from any liability for failing to deliver gas, or subject the NGDC to any liability resulting from the NGS’s failure to deliver.

 (d)  Natural gas service to interruptible gas service customers should be interrupted, pursuant to the terms and conditions of the NGDC’s tariff, if the safety and reliability of firm service would be impeded by the interruptible customer’s continued use of natural gas.

 (a)  The SOLR is the NGDC or an NGS, which has been designated by the Commission under section 2207 of the act (relating to obligations to serve) to provide SOLR service. Each of the following services will be provided by an SOLR:

   (1)  Natural gas supply services to those customers who have not chosen an alternative NGS or who choose to be serviced by their SOLR.

   (2)  Natural gas supply services to those customers who are refused supply service from an NGS.

   (3)  Natural gas supply services to those customers whose NGS has failed to deliver its requirements.

 (b)  A customer should not have more than one SOLR designated for any of the services in subsection (a).

 (c)  An SOLR under subsection (a)(3) should provide sufficient supplies as to quantity, quality, pressure and location to meet the operational reliability requirements of the NGDC’s system including a failure of one or more NGSs to do one of the following:

   (1)  Supply natural gas to their retail gas customers in conformance with their contractual obligations to the customers.

   (2)  Satisfy applicable reliability standards and obligations.

 An NGDC should, in addition to performing any other roles such as selling natural gas, function as the system operator in ensuring that its distribution system is designed, constructed, managed and operated to safely and reliably receive and deliver natural gas throughout its facilities to customers connected to them. An NGDC, in performing its responsibilities as a system operator, may retain or acquire gas supply assets as required to perform its system operator functions in a manner which permits it to operate its system in a safe and reliable manner. The identity of the gas supply assets utilized by the NGDC to perform its system operator function should be reviewed by the Commission annually in the NGDC’s Section 1307(f) proceeding as part of the NGDC’s reliability plan.

 (a)  NGSs using firm gas supply contracts with Pennsylvania producers or storage or transportation capacity contracts acquired through assignment or release by NGDCs or acquired as the result of the nonrenewal of a storage or transportation capacity contract previously held by the NGDC should offer the SOLR, or the successor NGS, a right of first refusal to utilize the contracts at the NGS’s contract cost as long as needed to serve retail gas customers being relinquished by the NGS.

 (b)  NGSs using storage or transportation capacity contracts acquired in a manner other than through assignment, release or nonrenewal by the NGDC should provide the SOLR a right of first refusal to use the capacity at contract cost if the NGS failed to give the SOLR and the NGDC sufficient notice or if there is insufficient alternative capacity available to serve the market being relinquished by the NGS.

   (1)  The SOLR may retain the right to use the capacity at cost until the SOLR, through reasonable and diligent efforts, is able to acquire replacement capacity sufficient to serve the customers being relinquished by the NGS.

   (2)  The NGDC or the SOLR should acquire the replacement capacity in a manner consistent with the Commission’s least cost fuel procurement policy.

 Nonperformance penalties should be established at levels sufficiently high to deter NGSs from failing to comply with their delivery obligations.

   (1)  The penalties should be independent of and in addition to the costs incurred by the NGDC, or, in the alternative, the supplier of last resort, for replacement gas supplies, including pipeline penalties.

   (2)  NGDCs may take into consideration the operational costs and other liabilities NGDCs may be exposed to by virtue of an NGS’s failure to deliver in establishing penalties.

   (3)  Failure of an NGS to honor delivery obligations may lead to disqualification from NGDC programs, suspension or revocation of the NGSs license.

   (4)  The disqualification, suspension or revocation should not relieve the NGS of its obligations to pay all penalties and costs incurred by the NGDC as a result of the NGS’s failure to deliver.

 (a)  A critical period exists when the NGDC declares an Operational Flow Order (OFO). A critical period implies the need for heightened awareness and attention by all parties.

   (1)  OFOs are issued to alleviate stress, or potential stress, to the NGDC system that threatens safety or reliability, or both.

   (2)  OFOs are an action of last resort, are never issued lightly, and are only issued for safety or reliability reasons.

   (3)  OFOs are distinct from, and do not preclude, other types of flow orders which an NGDC may issue to satisfy other obligations of the NGDC or the SOLR under the code or this title, such as the obligation to fulfill the least cost fuel procurement requirements of section 1318 of the act (relating to determination of just and reasonable gas cost rates).

 (b)  The NGDC should describe in detail, in its tariff, the actions it will take in advance of, and during a critical period. At a minimum, those actions should include the following:

   (1)  Exercises wherein critical period communications between, and the required responses of, the parties can be tested.

   (2)  A protocol for issuing and communicating system alerts that announce actual or pending events that, if unchecked, may result in a critical period, and call for voluntary actions or responses from NGSs and customers.

   (3)  A protocol for issuing and communicating OFOs. The protocol should address how and when the OFOs will be announced, and provide for disseminating periodic status reports during the period an OFO is in effect. OFOs should state the actions required and the reasons for the actions, be as localized as possible and be applied in a nondiscriminatory manner.

 Communications protocols are tools by which NGDCs, NGSs and other parties, define and describe the type, form and frequency of communications necessary to successfully fulfill customer requirements in an operating environment of increased retail choice. Effective and consistent communications are critical to reduce errors, and provide all entities with the information necessary to properly fulfill their respective responsibilities, both in normal and emergency circumstances. A communications protocol should include at minimum, in addition to the specific requirements in §  69.17(b)(2) and (3) (relating to critical period procedures) the following:

   (1)  A detailing of contact data for both NGDC and NGS personnel responsible for the various aspects of customer contact, gas deliveries and distribution, including mechanisms for ensuring that the data is kept current for all parties.

   (2)  The specification that regular meetings will be held, with joint agenda development responsibilities, including the potential scheduling of operational conference calls.

   (3)  Communications, to the extent not otherwise set forth in the NGDC’s tariff, associated with the NGDC’s procedures for customer enrollment, billing arrangements, daily or monthly delivery quantity determination, nominations (monthly, daily, intra-day, and weekend), balancing options, reconciliation or true-ups, cash-outs and electronic data exchange requirements.

 (d)  Procedures utilized by NGDCs to inform NGSs of changes to NGS delivered supplies or customer demand, or both, required to assure system reliability, both daily and seasonal, and to avoid pipeline penalties.

 (a)  Each NGDC should create an operational and capacity council for parties referred to in section 2204(f) of the act (relating to implementation) to discuss and attempt to resolve operational and capacity issues related to customer choice, including the reliability effects of those operational and capacity issues related to customer choice and the ongoing implementation of this section and § §  69.11—69.18 (relating to safety and reliability guidelines). The intent of these councils is to explore the possibility of building consensus among council participants relating to operational, capacity and operational and capacity-related safety and reliability issues in a fair and nondiscriminatory manner.

 (b)  Each NGDC’s operational and capacity council should, at a minimum, establish, in consultation with council participants, the following:

   (1)  A regular meeting schedule.

   (2)  An agenda for each meeting.

 (c)  The final determination of operational and reliability issues resides with the NGDC, subject to Commission review.

 (d)  The fact that statements were made, or positions were taken and were not considered or accepted, in operational and capacity council meetings should not be considered, or entered into evidence, in any formal proceeding before the Commission relating to any matter addressed in the council meetings.

   The provisions of these § §  69.21—69.27 adopted October 9, 1976, effective October 10, 1976, 6 Pa.B. 2513; reserved December 14, 2001, effective December 15, 2001, 31 Pa.B. 6800. Immediately preceding text appears at serial pages (271646) to (271650), (201989) to (201990) and (263695) to (263696).

   Hospital

   When based on consideration of the technical and economic feasibility of conversion to alternate fuels, it is reasonable to classify a hospital, two of whose three boilers have a dual-fire capability and which has an 8000 gallon on-site fuel-oil storage capacity, as a 99% Priority 6 customer. Montefiore Hospital Association v. Pennsylvania Public Utility Commission, 421 A.2d 481 (Pa. Cmwlth. 1980).

   High Rise Apartment

   A high rise apartment building may be classified as Priority 6, since the operator of the building is the customer of the gas company and, in turn, furnishes natural gas to its tenants, and since the building could not be classified as Priority 1 and also could not be classified as industrial. Housing Authority v. Pennsylvania Public Utility Commission, 406 A.2d 591 (Pa. Cmwlth. 1979).

   Overrun Revenue

   The Commission did not err or abuse its discretion in including overrun revenue in a purchased gas cost proceeding under section 1307(f), 66 Pa.C.S. §  1307. Because the utility’s core customers, rather than the utility’s shareholders, bore the risk of service interruption, then the utility’s core customers, rather than its shareholders, should receive the benefit of the overrun revenues. UGI Utilities v. Pennsylvania Utility Commission, 673 A.2d 43 (Pa. Cmwlth. 1996).

   Validity of Regulation

   The penalty provisions of 52 Pa. Code §  69.25 for unauthorized overruns of allocated volumes are rationally related to enforcement of the Commission’s natural gas curtailment scheme and are not arbitrary. Montefiore Hospital Association v. Pennsylvania Public Utility Commission, 421 A.2d 481 (Pa. Cmwlth. 1980).

COMMISSION POLICY STATEMENT ON ELECTRIC UTILITY
FINANCING OF ENERGY SUPPLY ALTERNATIVES

§ 69.31. Importance of energy supply alternatives.

 The Commission believes that energy supply alternatives such as conservation, load management, and alternate energy supply products are viable supply options which must be considered by the jurisdictional electric utilities as alternatives to capacity expansion and to reduce operating costs.

   The provisions of this §  69.31 issued under the Public Utility Code, 66 Pa.C.S. §  308(c).

 Reasonable and prudently incurred costs associated with the development, management, and operation of a cost effective alternative to energy supply shall be afforded rate treatment at least on a par with any other supply option.

   The provisions of this §  69.32 issued under the Public Utility Code, 66 Pa.C.S. §  308(c).

 Subject to Commission approval, electric utilities may request recovery of costs of energy supply alternatives by methods such as treating them as normal operating expenses, amortizing them over several years, capitalizing them for inclusion in rate base, or any combination thereof. Based upon Commission policy and recent Commission actions, the utilities shall determine how they will design their rate filings to recover these costs.

   The provisions of this §  69.33 issued under the Public Utility Code, 66 Pa.C.S. §  308(c).

 Energy supply alternatives may include but are not limited to conservation programs, load reducing or load shifting programs, and alternate energy supply projects.

   The provisions of this §  69.34 issued under the Public Utility Code, 66 Pa.C.S. §  308(c).

 A common evaluation methodology, developed by the Commission with the cooperation and assistance of the utilities, will be utilized to determine whether an energy supply alternative may be considered cost effective.

   The provisions of this §  69.35 issued under the Public Utility Code, 66 Pa.C.S. §  308(c).

 The Pennsylvania Public Utility Commission intends to examine specific factors in rate proceedings of electric and gas utilities regarding the action or failure to act to encourage development of cost effective energy supply alternatives. Specifically, the Commission will review utilities’ efforts to meet the criteria inthis section when determining just and reasonable rates in future rate proceedings and may consider those efforts in other proceedings instituted by the Commission.

   (1)  Information. At least twice annually utilities should provide customers with information on specific means of utilizing their energy services more effectively and efficiently. Topic areas should include insulation, lighting efficiencies, appliance efficiencies, conservation practices, load management techniques or other relevant information that informs the customer of the efficient use of energy.

   (2)  Energy surveys. Class A utilities should offer onsite energy surveys to the residential, commercial and industrial classes on an ongoing basis. Surveys should be conducted by trained personnel and the results of the survey, upon written request of the customer, be delivered in writing with a clear explanation of the resulting components.

   (3)  Cogeneration and small power production. Electric utilities for which a need for capacity is projected should establish effective programs to explore and encourage the development of additional cogeneration and small power production facilities within their respective service territories.

   (4)  Least cost planning. Gas and electric utilities should actively pursue a least-cost strategy by acquiring and developing the resources necessary to effectively meet their customers’ future energy needs, consistent with established availability and reliability criteria. Utilities should make a reasonable effort to promote the utilization of practical and economical energy conservation and demand management through cost effective programs.

   (5)  Evaluation. Class A utilities should demonstrate progressive work regarding development of a reliable customer data base, including, but not limited to:

     (i)   End-use applications for each class of customer in terms of energy and demand.

     (ii)   Customer behavior with regard to the decision-making process.

     (iii)   The impact of program decisions or strategies and how they effect the overall planning process.

   (6)  Natural gas co-firing. Electric utilities should explore the potential for increasing capacity and output at coal-fired generating stations through gas cofiring.

   The provisions of this §  69.44 adopted March 4, 1977, effective March 5, 1977, 7 Pa.B. 577; reserved June 29, 1984, effective June 30, 1984, 14 Pa.B. 2250. Immediately preceding text appears at serial pages (33028) and (66641).

INCLUSION OF STATE TAXES AND GROSS RECEIPTS TAXES IN BASE RATES

§ 69.51. Definitions.

 The following words and phrases, when used in § §  69.51—69.56, have the following meanings, unless the context clearly indicates otherwise:

   Gross receipts tax rider—The separate rider which certain gas utilities impose on customer bills at a rate of 2.04% to collect the 20 mills gross receipts tax which was in effect prior to January 1, 1970. On that date the gross receipts tax was increased by 25 mills, which additional amount was included in the State tax adjustment surcharge.

   State tax adjustment surcharge—The surcharge implemented under the State Tax Adjustment Procedure Order of the Commission dated March 10, 1970, as amended, which permits utilities under its jurisdiction to recover portions of the Capital Stock Tax, Corporate Net Income Tax and Gross Receipts Tax and the Public Utility Realty Tax through a surcharge on rates charged to customers.

   The provisions of this §  69.51 issued under Public Utility Code,66 Pa.C.S. § §  501, 1301, 1302, 1504 and 1509.

   The provisions of this §  69.51 adopted January 8, 1988, effective January 9, 1988, 18 Pa.B. 185.

   Unless necessitated by a change in the Pennsylvania Capital Stock Tax, Corporate Net Income Tax, Gross Receipts Tax or Public Utility Realty Tax which would increase or decrease rates in a manner governed by the Commission’s State Tax Adjustment Procedure, 44 Pa. P.U.C. 545 (1970), a utility which has a State tax adjustment surcharge or gross receipts tax rider shall maintain its surcharge and rider rates at 0%.

   The provisions of this §  69.52 issued under Public Utility Code,66 Pa.C.S. § §  501, 1301, 1302, 1504 and 1509.

   The provisions of this §  69.52 adopted January 8, 1988, effective January 9, 1988, 18 Pa.B. 185.

   (Editor’s Note: The following Exhibit is codified under 1 Pa. Code §  3.1(a)(9) (relating to contents of Code) as a document which the Legislative Reference Bureau finds to be general and permanent in nature.)

Exhibit A
STATE TAX ADJUSTMENT PROCEDURE

   BY THE COMMISSION, March 10, 1970:

 By enactments at the end of 1969 and during February of 1970, the Legislature has retroactively increased the rates of three types of taxes paid by public utilities, and has imposed a new tax upon real estate of public utilities, as follows:

 It should be noted here that the increase of 25 mills in the gross receipts tax, which will produce the greatest tax revenues, was enacted as a temporary tax effective for the period January 1, 1970 to September 1, 1971. Prescribed assessment procedures for the realty tax may cause the relative effective rate for each utility to fluctuate in subsequent years. It is also possible that predicted tax reform may modify or eliminate these recent tax increases.

 Public utilities under our jurisdiction are subject to regulation, which permits them to recover, in the form of rates, their legitimate costs, plus a fair return which compensates investors for the use of the funds they have provided for the construction of utility facilities.

 The new and increased taxes constitute a legitimate cost, and, unless compensated for, will reduce the return of public utilities at a time when many of them, particularly the electric and telephone groups, are engaged in unprecedented construction programs in order to assure adequate facilities for service to customers. These large construction programs must be financed by attracting funds from investors; and such attraction will be difficult in many instances, and impossible in others, if the returns of the public utilities are permitted to decline appreciably as a result of these increases in taxes. Unless relief is granted, there could be serious deterioration of service to the public.

 The public utilities are deluging us with requests to preserve their present returns by filing individually for rate increases which are retroactive because the new taxes are retroactive and any delay for rate relief would make the impairment of return inescapable. We have 620 electric, gas, water and telephone utilities, as well as many utilities of other types, under our jurisdiction and to attempt to give necessary and prompt relief on an individual basis would be an impossibility.

 A more sensible and practicable approach is to temporarily allow those public utilities which are affected by the increased taxes to recover, prospectively but not retroactively, such costs by a surcharge on service furnished after the charge is approved; to study various long-term procedures; to compute the surcharge so as to prevent overcompensation for the increased costs; to provide for subsequent modification of the surcharge to reflect any elimination or modification of these tax increases; and to later review each public utility’s situation to enable us to require refunds or other remedies to customers in any appropriate case; THEREFORE,

 IT IS ORDERED:

 A. Every public utility which has been subjected to new or increased taxes enacted by the General Assembly of 1969-1970, and proposing to impose a surcharge to recover such taxes, shall compute the surcharge in the following manner and submit the computation to this Commission:

   1. The one-mill increase in the capital stock and franchise tax rate shall be applied to the most recently settled valuation placed on the utility for that tax.

   2. For the 4 1/2% increase in the corporate net income tax rate, add together (a) the Pennsylvania corporate net income tax liability for the most recently completed calendar year and (b) the net income, as defined in Section 2 of the Corporate Net Income Tax Act, upon which that liability was computed; and multiply the resulting total by (c) the factor 4.186%. (Note: This factor is the increase of 3.738% in the effective tax rate, divided by .983 which is the complement of the effective tax rate; and this factor shall be changed if the effective tax rate changes.)

   3. The new 30-mill Public Utility Realty Tax shall be applied to the utility’s ‘‘State taxable value’’ (as defined in section 2(d) of the tax act) at the end of the most recently completed calendar year.

   4. For any utility subject to the gross receipts tax (act of 1889), the 25-mill increase in the gross receipts tax rate shall be applied to the gross receipts tax base for the most recently completed calendar year.

   5. Items 1, 2, 3, and 4 where applicable, shall be totaled.

   6. For any public utility subject to the gross receipts tax, the total of item 5 shall be divided by a factor which is the complement of the gross receipts tax rate (such factor being .955 as of the date of this order).

   7. The total of item 5 for any utility not subject to the gross receipts tax, and the quotient of item 6 for any utility subject to such tax, shall be divided by the utility’s gross intrastate operating revenues derived from service under rates subject to the jurisdiction of this Commission for the most recently completed calendar year, exclusive of the revenues produced by the surcharge permitted by Section A. The quotient of such division shall be expressed as a percentage.

   8. If the utility shall have increased or decreased its rates under this Commission’s jurisdiction during or after the most recently completed calendar year, it shall include in its computation the appropriate adjustments to items 2, 4, 5, 6, and 7, as if such increased or decreased rates had been in effect for all of such year.

   9. The surcharge imposed shall not exceed the percentage determined by item 7, subject to the adjustments prescribed by item 8.

   10. Any public utility which, prior to the effective date of its initial surcharge permitted by this order, shall have placed new rates in effect, or has filed a proposed rate increase, which include any compensation for the tax increases referred to in section A, shall adjust those rates or filings to eliminate such compensation, and instead incorporate those increases in the surcharge permitted by this order as prescribed by section A.

 B. Every tariff or supplement imposing such surcharge shall provide that the utility will recompute the surcharge, using the elements prescribed by section A:

   1. Whenever any of the tax rates referred to in section A is changed, in which case the recomputation shall take into account the changed tax rate.

   2. Whenever the utility makes effective increased or decreased rates under this Commission’s jurisdiction, in which case the recomputation shall take into account the adjustments prescribed by section A-8.

   3. And on March 31, 1971, and each year thereafter.

 C. Every tariff or supplement imposing such surcharge shall also provide that every recomputation prescribed by section B shall be submitted to this Commission within ten days after the occurrence of the event or date which occasions such recomputation; and that if the recomputed surcharge is less than the one then in effect the utility will, and if the recomputed surcharge is more than the one then in effect the utility may, accompany such recomputation with a tariff or supplement to reflect such recomputed surcharge.

 D. Every tariff or supplement filed pursuant to this order shall carry an effective date which shall be ten days after its filing with this Commission, and be applicable for service rendered on or after the effective date.

 E. Nothing in this order shall be deemed to preclude this Commission from investigating the financial affairs of any utility and, in appropriate cases, ordering refunds or other proper remedies for its customers. This order is intentionally couched in permissive rather than mandatory language, to preclude the possibility that any surcharge imposed hereunder is a Commission-made rate.

   A fixed service utility which has a State tax adjustment surcharge shall roll revenues collected through the surcharge into base rates to set the surcharge rate at 0%.

   The provisions of this §  69.53 issued under Public Utility Code,66 Pa.C.S. §  501, 1301, 1302, 1504 and 1509.

   The provisions of this §  69.53 adopted January 8, 1988, effective January 9, 1988, 18 Pa.B. 185.

   A fixed service utility which has a gross receipts tax rider shall roll revenues collected through the rider into base rates to set the rider rate at 0%.

   The provisions of this §  69.54 issued under Public Utility Code,66 Pa.C.S. § §  501, 1301, 1302, 1504 and 1509.

   The provisions of this §  69.54 adopted January 8, 1988, effective January 9, 1988, 18 Pa.B. 185.

 Compliance with §  69.53 (relating to zeroing of State tax adjustment surcharge) or §  69.54 (relating to zeroing of gross receipts tax rider) shall be accomplished in one of the following manners:

   (1)  Rate case method. If a utility has on file a State tax adjustment surcharge or gross receipts tax rider at a rate other than zero, the State tax adjustment surcharge and gross receipts tax rider shall be zeroed and the tax expense recovered by the surcharge and rider shall be rolled into base rates in the next general rate increase filed by the utility. If the utility files a cost of service study with its proposed rate increase, the tax expense previously recovered through the surcharge and rider shall be allocated to the various classes of service in a manner consistent with the cost of service study. If a cost of service study is not provided with the rate filing, the surcharge and rider revenues shall be rolled into base rates by applying the same percentage rate to each class of service so that there will be no effective change in total revenues recovered from each service classification as a result of the roll-in.

   (2)  Nonrate case method. The State tax adjustment surcharge and gross receipts tax rider shall be zeroed, and the tax expenses recovered through application of the surcharge and rider shall be rolled into base rates by filing a tariff or tariff supplement and supporting data on 60-days’ statutory notice to the Commission. The transfer of revenues to base rates shall be accomplished so that there will be no effective change in total revenues recovered from each service classification as a result of the roll-in. The supporting data shall include calculations showing the development of the new tariff rates as well as the revenues which they will produce on an annual basis. Customers shall be advised of the roll-in of the surcharge and rider revenues by bill insert to be mailed during the normal monthly or quarterly billing cycle.

   The provisions of this §  69.55 issued under Public Utility Code,66 Pa.C.S. § §  501, 1301, 1302, 1504 and 1509.

   The provisions of this §  69.55 adopted January 8, 1988, effective January 9, 1988, 18 Pa.B. 185.

 Tariff filings effectuating the zeroing of the State tax adjustment surcharge and gross receipts tax rider shall be submitted to the Commission by January 9, 1990, or thereafter, within 24 months of a change in the State tax adjustment surcharge or gross receipts tax rider which causes either to be set at a rate other than zero.

   The provisions of this §  69.56 issued under Public Utility Code,66 Pa.C.S. § §  501, 1301, 1302, 1504 and 1509.

   The provisions of this §  69.56 adopted January 8, 1988, effective January 9, 1988, 18 Pa.B. 185.

   The provisions of this §  69.85 adopted May 18, 1984, effective May 19, 1984, 14 Pa.B. 1713; reserved March 17, 2000, effective March 6, 1999, 30 Pa.B. 1548. Immediately preceding text appears at serial page (255447).

TARIFF PROVISIONS THAT LIMIT THE LIABILITY OF UTILITIES FOR INJURY OR DAMAGE AS A RESULT OF NEGLIGENCE OR INTENTIONAL TORTS—STATEMENT OF POLICY

§ 69.87. Tariff provisions that limit the liability of utilities for injury or damage as a result of negligence or intentional torts—statement of policy.

 The Commission, after review of applicable State law, and on consideration of the various policy considerations relative to the inclusion in tariffs of provisions which limit the liability of utilities for injury or damages as a result of negligence or intentional torts, finds that State law permits utilities to limit their liability for interruption or cessation of service. If a utility seeks to place the language in its tariff, a tariff filing should be made under section 1308 of the code (relating to voluntary changes in rates), and should include a company-specific dollar amount for the proposed limitation and work papers to substantiate the dollar amount. A copy of the tariff filing should be served on the Office of Consumer Advocate and on the Office of Small Business Advocate.

   The provisions of this §  69.87 adopted April 23, 1999, effective April 24, 1999, 29 Pa.B. 2147.

DISPOSITION OF COMPLAINTS IN RATE CASES

§ 69.91. Policy.

 (a)  In rate cases where either an ‘‘option order’’ or a settlement petition is approved by the Commission, there may arise a problem of the prompt resolution of any outstanding complainant where the complaint does not acquiesce to the approved option or settlement and, instead, elects to pursue the outstanding complaint. Oftentimes resolution of the outstanding complaint does not occur within the statutory suspension period, but rather extends well beyond the period required to decide a rate case.

 (b)  The Commission believes that lengthy and avoidable delays in the disposition of consumer complaints in rate cases which are optioned or settled undermine public trust in our rate setting process. Further, delay makes the administration of any refund found appropriate, should the complainant ultimately prevail on the merits, more difficult.

 (c)  Therefore, to the extent practicable, it is the policy of the Commission to:

   (1)  Require in any option order or order approving a settlement petition, that the Office of Administrative Law Judge proceed with hearings on any outstanding complaint, where desired by the complainant, on a schedule that would provide the Commission with a recommended decision in sufficient time for a final Commission order within the statutory suspension period which would have applied had the case not been optioned or settled; and

   (2)  Issue a final Commission order on any outstanding complaint, where desired by the complainant, within the statutory suspension which would have applied had the case not been optioned or settled.

   The provisions of this §  69.91 issued under the Public Utility Code, 66 Pa.C.S. § §  501, 703 and 1308.

   The provisions of this §  69.91 adopted April 8, 1983, effective April 9, 1983, 13 Pa.B. 1258.

BUILDING ENERGY CONSERVATION STANDARDS FOR RECEIPT
OF UTILITY SERVICE

§ 69.101. Definitions.

 The following words and terms, when used in § §  69.101—69.107, have the following meanings, unless the context clearly indicates otherwise:

   Act—The Building Energy Conservation Act (35 P. S. § §  7201.101—7201.602).

   Addition—An addition to an existing building. See §  69.102 (relating to scope).

   Building energy conservation standards—The standards promulgated by the Department at 12 Pa. Code Chapter 147 (relating to building energy conservation standards).

   Compliance certification copy—The part of the notice of intent to construct returned by the Department or municipality after receipt and processing of the notice of intent to construct, which bears the ID number assigned to the notice of intent to construct by the Department or municipality.

   Department—The Department of Community Affairs of the Commonwealth.

   Municipality—A city, borough, incorporated town, township or home rule municipality which has elected to administer the act under section 501 of the act (35 P. S. §  7201.501).

   Notice of intent to construct—The notice required to be filed with the Department, or a municipality, under section 306 of the act (35 P. S. §  7201.306).

   Person—Individuals, partnerships, associations, sole proprietorships, companies, corporations and their lessees, assignees, trustees, receivers, executors, administrators or other successors in interest.

   Public utility—Persons or corporations in this Commonwealth owning or operating equipment or facilities for producing, generating, transmitting, distributing or furnishing electricity to or for the public for compensation for any purpose. The term does not include the following:

     (i) A generator or producer of electricity not engaged in distributing the electricity directly to the public for compensation.

     (ii) A person not otherwise a public utility who furnishes service only to himself.

     (iii) A bona fide cooperative association which furnishes services only to its stockholders or members on a nonprofit basis.

   Renovation—The rehabilitation of an existing building which requires more than 25% of the gross floor area or volume of the entire building to be rebuilt. Cosmetic work, such as painting, wall covering, wall paneling, floor covering and suspended ceiling work is not required to be included. Sections 69.101—69.107 apply to the portion of the building being renovated and not to the entire building.

   Residential building—A building as defined in section 103 of act (35 P. S. §  7201.103), and renovations thereto, the actual construction of which commenced after March 19, 1986, and which is arranged for the use of one or two family dwelling units, and rowhouses, townhouses and garden apartment construction not exceeding three stories in height used for residential purposes, whenever each unit has its own individual and self-supporting heating, ventilating or air conditioning system.

   The provisions of this §  69.101 issued under Public Utility Code,66 Pa.C.S. § §  308, 501, 1501 and 1704; amended under Public Utility Code,66 Pa.C.S. § §  308, 331, 501, 1501 and 1704.

   The provisions of this §  69.101 adopted April 20, 1984, effective July 20, 1984, 14 Pa.B. 1393; amended January 23, 1987, effective January 24, 1987, 17 Pa.B. 389. Immediately preceding text appears at serial pages (90049) to (90051).

 (a)  Sections 69.101—69.107 apply to all applications for electric service to or for residential buildings received by a public utility after March 19, 1986.

 (b)  Sections 69.101—69.107 apply to the portion of the building which is being added and not to the entire building.

   The provisions of this §  69.102 issued under Public Utility Code,66 Pa.C.S. § §  308, 501, 1501 and 1704; amended under Public Utility Code,66 Pa.C.S. § §  308, 331, 501, 1501 and 1704.

   The provisions of this §  69.102 adopted April 20, 1984, effective July 20, 1984, 14 Pa.B. 1393; amended January 23, 1987, effective January 24, 1987, 17 Pa.B. 389. Immediately preceding text appears at serial page (90051).

 Except as provided in §  69.107 (relating to exemptions), a public utility, prior to furnishing electric service to or for a residential building, shall require that the compliance certification copy be submitted to it by the person requesting service to or for the residential building. A public utility shall require that the compliance certification copy be submitted not later than the date on which electric service to or for a residential building is provided by the utility.

   The provisions of this §  69.103 issued under Public Utility Code,66 Pa.C.S. § §  308, 501, 1501 and 1704; amended under Public Utility Code,66 Pa.C.S. § §  308, 331, 501, 1501 and 1704.

   The provisions of this §  69.103 adopted April 20, 1984, effective July 20, 1984, 14 Pa.B. 1393; amended January 23, 1987, effective January 24, 1987, 17 Pa.B. 389. Immediately preceding text appears at serial page (90051).

 (a)  The receipt by a public utility of the compliance certification copy constitutes conclusive evidence to the utility that the residential building, for which electric service has been requested, has been or will be constructed in compliance with the building energy conservation standards. Public utilities shall rely absolutely on the compliance certification copy in furnishing electric service to or for a residential building, and no public utility, which is in receipt of the compliance certification copy may conduct an audit, examination or inspection of the residential building for the purpose of determining compliance with the building energy conservation standards.

 (b)  The furnishing, rendering or supplying of electric service to or for a residential building by a public utility, in reliance upon the compliance certification copy may not constitute a certification or determination by the utility that the residential building has been constructed in compliance with the building energy conservation standards.

   The provisions of this §  69.104 issued under Public Utility Code,66 Pa.C.S. § §  308, 501, 1501 and 1704; amended under Public Utility Code,66 Pa.C.S. § §  308, 331, 501, 1501 and 1704.

   The provisions of this §  69.104 adopted April 20, 1984, effective July 20, 1984, 14 Pa.B. 1393; amended January 23, 1987, effective January 24, 1987, 17 Pa.B. 389. Immediately preceding text appears at serial pages (90051) and (95685).

 Except as provided in §  69.107 (pertaining to exemptions), no public utility may furnish electric service to a residential building unless it has first received the compliance certification copy.

   The provisions of this §  69.105 issued under Public Utility Code,66 Pa.C.S. § §  308, 501, 1501 and 1704; amended under Public Utility Code,66 Pa.C.S. § §  308, 331, 501, 1501 and 1704.

   The provisions of this §  69.105 adopted April 20, 1984, effective July 20, 1984, 14 Pa.B. 1393; amended January 23, 1987, effective January 24, 1987, 17 Pa.B. 389. Immediately preceding text appears at serial page (95685).

 A public utility shall be required to retain the compliance certification copy which is submitted to it for at least 2 years. If a public utility uses data processing equipment to record and maintain information derived from the compliance certification copy, the utility may not be required to retain the compliance certification copy.

   The provisions of this §  69.106 issued under Public Utility Code,66 Pa.C.S. § §  308, 501, 1501 and 1704; amended under Public Utility Code,66 Pa.C.S. § §  308, 331, 501, 1501 and 1704.

   The provisions of this §  69.106 adopted April 20, 1984, effective July 20, 1984, 14 Pa.B. 1393; amended January 23, 1987, effective January 24, 1987, 17 Pa.B. 389. Immediately preceding text appears at serial page (95685).

 (a)  A public utility is exempt from § §  69.103—69.106 (relating to utilities to require receipt of compliance certification copy of notice of intent to construct; reliance upon compliance certification copy; effect of reliance; service to certain residential buildings prohibited; and record retention), for an application for electric service to or for a residential building which is located in a municipality which has elected under sections 501 and 502 of the act (35 P. S. § §  7201.501 and 7201.502) to administer the act and which requires that a notice of intent to construct be filed with the municipality prior to or at the time that a building permit is applied for.

 (b)  A public utility is exempt from § §  69.103—69.106, if in the utility’s judgment, strict compliance may jeopardize the public health or safety or impose an undue hardship. In this event, the utility shall notify the Department or the municipality, in writing, of the exemption.

   The provisions of this §  69.107 issued under Public Utility Code,66 Pa.C.S. § §  308, 501, 1501 and 1704; amended under Public Utility Code,66 Pa.C.S. § §  308, 331, 501, 1501 and 1704.

   The provisions of this §  69.107 adopted April 20, 1984, effective July 20, 1984, 14 Pa.B. 1393; amended January 23, 1987, effective January 24, 1987, 17 Pa.B. 389. Immediately preceding text appears at serial pages (95685) to (95686).

   The provisions of these § §  69.153—69.168 adopted July 31, 1987, effective August 1, 1987, 17 Pa.B. 3220; reserved January 15, 1993, effective January 16, 1993, 23 Pa.B. 265. Immediately preceding text appears at serial pages (126877) to (126878).

POLICY STATEMENT INTERPRETING TERMS
INCLUDED IN 66 PA.C.S. §  1326

§ 69.169. Definitions—statement of policy.

 The following words and terms, used in 66 Pa.C.S. §  1326 (relating to standby charge prohibited), have the following meanings:

   Residential structure—A building which contains only individually metered dwelling units intended for human habitation.

   Standby charge—The charge for the availability of water supply during fire emergencies. Costs for the upsizing of company-owned service lines and meters, for the installation of additional lines and for backflow prevention devices are not standby charges for purposes of residential sprinkler systems, and these costs shall be borne by the applicant for service on a one-time basis.

   The provisions of this §  69.169 adopted June 30, 1989, effective July 1, 1989, 19 Pa.B. 2787.

LINE EXTENSIONS

§ 69.171. [Reserved].

   The provisions of this §  69.171 adopted September 18, 1992, effective September 19, 1992, 22 Pa.B. 4699; reserved February 14, 1997, effective February 15, 1997, 27 Pa.B. 799. Immediately preceding text appears at serial page (222438).

   Retroactive Application

   The provisions of this §  69.181 adopted August 4, 1989, effective August 5, 1989, 19 Pa.B. 3304; reserved March 29, 1996, effective March 30, 1996, 26 Pa.B. 1377. Immediately preceding text appears at serial pages (202014) to (202016).

   Cost Assignment

   A utility may not recover the carrying costs associated with the amortization of an operating expense. Not only would this allow a utility to capitalize an item in its rate base and at the same time recover an item as expense from taxpayers, but it would also undermine the Public Utility Commission’s policy, as codified by this regulation, to balance the interest of shareholders and ratepayers, and to fairly spread the cost of TOP expenses which arose out of gas distribution company’s failure to purchase gas at its full contract requirements level. National Fuel Gas Distribution Corp. v. Pennsylvania Public Utility Commission, 677 A.2d 861 (Pa. Cmwlth. 1996).

   General Comments

   This regulation is a statement of policy and does not have the force of law. It is only an indication of how the Public Utility Commission intends to proceed. UGI Utilities, Inc. v. Pennsylvania Public Utility Commission, 677 A.2d 882 (Pa. Cmwlth. 1996).

   Refund Granted

   Administrative law judge’s decision to order the utility company to refund its customers 90% of its take-or-pay refund, including interest, was upheld. UGI Utilities, Inc. v. Pennsylvania Public Utility Commission, 677 A.2d 882 (Pa. Cmwlth. 1996).

   Refunds

   Natural gas company was required to refund 90% of its take-or-pay refund, including interest, despite company’s contention that the decision was contrary to the take-or-pay refund policy statement and to the Public Utility Commission’s prior application of that statement to the company. Peoples Natural Gas Co. v. Pennsylvania Public Utility Commission, 677 A.2d 890 (Pa. Cmwlth. 1996); appeal denied 688 A.2d 174 (Pa. 1997).

   The witness testified that there was no analysis or quantification by the gas company of the time value of the money lost to ratepayers, that is the lag between the times that ratepayers made payments to the gas company for TOP costs, and the time the ratepayers received a refund. Therefore, the gas company failed to carry its burden to prove its equitable argument that it, and not the ratepayers, was entitled to a refund. National Fuel Gas Distribution Corp. v. Pennsylvania Public Utility Commission, 677 A.2d 861 (Pa. Cmwlth. 1996).

POLICY STATEMENT ADDRESSING AFFILIATED
INTEREST ISSUES OF NATURAL GAS
MARKETERS

§ 69.191. General.

 (a)  Given the unbundling of monopoly distribution services in the natural gas industry and the development of customer access to commodity gas and transportation services, the Commission has developed policies for local distribution companies (LDCs), marketers and customers with regard to the affiliated and nonaffiliated interests of LDCs. Unless otherwise stated, the phrase ‘‘marketer’’ or ‘‘marketers or brokers’’ includes all LDC affiliates, subsidiaries, parents, divisions, and the like providing gas supply to a respective LDC’s customer. This section and §  69.192 (relating to affiliated interest—statement of policy) are intended to clarify additional aspects of the Commission’s authority in this area. The Commission has a strong policy against direct or indirect discrimination by LDCs in favor of their marketing affiliates or marketing divisions and against independent gas marketers. The discrimination impermissibly hinders the unbundling of services and the entry of new competitors into the marketplace. This discrimination also violates section 1502 of the code (relating to discrimination in service).

 (b)  Many Pennsylvania LDCs have affiliated marketing divisions. Some Pennsylvania LDCs may have divisions or marketing sections that are not separately organized as affiliates as defined in 66 Pa.C.S. (relating to Public Utility Code). This section and §  69.192 provide guidance to an LDC’s affiliate, regardless of the format used to operate an LDC’s affiliate, in order to be effective, to prevent discriminatory behavior, and insure compliance with section 1502 of the code (relating to discrimination in service). This section and §  69.192 will apply without regard to the structural relationship of the LDC’s marketer to the LDC.

 (c)  This section and §  69.192 cover both the LDC’s affiliates and gas marketing divisions or marketing sections, even those without any distinct organizational structure, that do not have affiliate status. This section and §  69.192 will not require any generic structural separation of an LDC’s affiliate, notwithstanding actions taken to the contrary in other states, because the Commission does not believe this is necessary as long as the LDC fairly allocates costs to an LDC’s affiliate and refrains from giving the LDC’s affiliate any unfair advantage vis-a-vis a marketer or broker not affiliated with an LDC. The Commission may impose such a structural requirement if and when warranted by the facts and circumstances.

 (d)  The Commission’s authority with respect to affiliates and marketing divisions derives from different portions of the code. Chapter 21 of the code (relating to relations with affiliated interests) directly governs affiliated interests. Section 1318(b) of the code (relating to just and reasonable natural gas rates), addresses gas purchased from affiliates. Other provisions govern natural gas costs such as sections 1307, 1308, 1317, and 1318. The code requires adherence to tariffs under section 1303 (relating to adherence to tariffs) and thus prohibits a lack of uniformity or discrimination in the application of tariff provisions. Likewise under section 1304 (relating to discrimination in rates) it prohibits rate discrimination. Other provisions reenforce these policies: section 1501 (relating to character of service and facilities) requires utilities to furnish ‘‘adequate, efficient, safe and reasonable service,’’ while section 1502 prohibits ‘‘any unreasonable preference or disadvantage’’ and forbids ‘‘any unreasonable prejudice or disadvantage.’’ These provisions require equal treatment of similarly situated parties, in this case customers of an LDC’s transportation tariff services, regardless of whether that customer chooses to use the gas supply services of an LDC or otherwise.

 (e)  Under sections 505 and 506 of the code (relating to duty to furnish information to the Commission; cooperation in valuing property; and inspection of facilities and records), the Commission has authority to require utilities to keep and furnish information in accordance with requirements set forth by the Commission. As part of this section and §  69.192 the Commission has set forth certain recordkeeping requirements to help ensure that parties are fairly treated. The Commission expects the LDC, in consultation with marketers or brokers to propose a process for reporting and managing marketer or broker complaints as part of any tariff proposed as a result of this section and §  69.192. The Commission may expect additional recordkeeping or conflict resolution processes if the parties are unable to resolve this or if warranted by subsequent facts and circumstances.

   The provisions of this §  69.191 adopted August 15, 1997, effective August 16, 1997, 27 Pa.B. 4102.

 The following policies should be applied by the local distribution companies (LDCs):

   (1)  The LDC should apply its tariffs in a nondiscriminatory manner to its affiliate, its own marketing division and any nonaffiliate.

   (2)  The LDC should likewise not apply a tariff provision in any manner that would give its affiliate or division an unreasonable preference over other marketers with regard to matters such as scheduling, balancing, transportation, storage, curtailment or nondelivery.

   (3)  If a tariff provision is mandatory, the LDC should not waive the provision for its affiliate or division absent prior approval of the Commission.

   (4)  If a tariff provision is not mandatory or provides for waivers, the LDC should grant the waivers without preference to affiliates and divisions or nonaffiliates.

   (5)  The LDC should maintain a chronological log of tariff provisions for which it has granted waivers. Entries should include the name of the party receiving the waiver, the date and time of the request, the specific tariff provision waived and the reason for the waiver. Any chronological log should be open for public inspection during normal business hours.

   (6)  The LDC should process requests for transportation promptly and in a nondiscriminatory fashion with respect to other requests received in the same or a similar period. The LDC should maintain a chronological log showing the processing of requests for transportation services. Any chronological log should be open for public inspection during normal business hours.

   (7)  Transportation discounts provided to the LDC’s or its marketing affiliate’s favored customers should be offered to other similarly situated customers and should not be tied to any unrelated service, incentive or offer on behalf of either the parent or affiliate. A chronological log should be maintained showing the date, party, time and rationale for the action. Any chronological log should be open for public inspection during normal business hours.

   (8)  The LDC should not disclose any customer proprietary information to its marketing affiliate or division, and to the extent that it does disclose customer information, it should do so to other similarly situated marketers in a similar fashion so as not to selectively disclose, delay disclosure, or give itself or its affiliate any undue advantage related to the disclosure. A chronological log should be maintained showing the date, time and rationale for the disclosure. Any chronological log should be open for public inspection during normal business hours.

   (9)  An LDC should justly and reasonably allocate to its marketing affiliate or division the costs or expenses for general administration or support services.

   (10)  An LDC selling surplus gas supplies and/or upstream capacity on a short-term basis (as defined by the Federal Energy Regulatory Commission’s definition) to its affiliate should make supplies available to similarly situated marketers on a nondiscriminatory basis. An LDC should not make any gas supplies and/or upstream capacity available through private disclosure to an LDC’s affiliate unless the availability is made simultaneously with public dissemination in a manner that fairly apprises interested parties of the availability of the gas supplies and/or upstream capacity. An LDC should maintain a chronological log of these public disseminations. Any chronological log should be open for public inspection during normal business hours.

   (11)  The LDC should not condition or tie agreements to release interstate pipeline capacity to any service in which the LDC or affiliate is involved.

   (12)  The LDC should not directly or by implication unfairly represent to any customer, supplier or third party that an advantage may accrue to any party through use of the LDC’s affiliate or subsidiary.

   (13)  The LDC should establish and file with the Commission a complaint procedure for dealing with any alleged violations of any of the standards listed in paragraphs (1)—(12), this paragraph or paragraphs (14) and (15), excepting for paragraph (9), which should be exclusively under the purview of the Commission. These procedures should be developed in consultation with interested parties during consideration of any tariff guided by this section and §  69.191 (relating to general). The Commission may expect establishment of a complaint procedure or other recordkeeping requirements if warranted by subsequent facts or circumstances.

   (14)  The LDC should keep a chronological log of any complaints, excepting paragraph (9), regarding discriminatory treatment of brokers. This chronological log should include the date and nature of the complaint and the LDC’s resolution of it. Any chronological log should be open for public inspection during normal business hours.

   (15)  Parties alleging violations of these standards may pursue their allegations through the Commission’s established complaint procedures. A complainant bears the burden of proof consistent with 66 Pa.C.S. (relating to Public Utility Code) in regard to the allegations.

   The provisions of this §  69.192 adopted August 15, 1997, effective August 16, 1997, 27 Pa.B. 4102.

   This section cited in 52 Pa. Code §  69.191 (relating to general).

UNIFORM STANDARDS FOR BROKERS AND MARKETERS

§ 69.195. Fitness of natural gas marketer or broker (including an LDC’s affiliate).

 (a)  Fitness of brokers and marketers.

   (1)  Unless otherwise stated, the phrase marketers or brokers, or both, includes all local distribution company (LDC) affiliates, subsidiaries, parents, divisions, and the like providing gas supply to the respective LDC’s customers.

   (2)  To retain reliable service when the gas industry unbundles, the Commission seeks to insure that brokers and marketers operating in this Commonwealth possess the financial or technical, or both, fitness necessary to meet their obligations consistent with the public interest in system reliability and gas supplies. As assurance of the continuation of reliable service and secure supplies is a prerequisite for opening Pennsylvania’s gas markets to full retail competition, both new and incumbent providers of gas should be fully capable of providing reliable service and supplies.

   (3)  The LDCs should address the issue of financial and technical fitness in their tariffs, in consultation with marketers or brokers, to assure the reliability of supplies to the end user and the public interest in system reliability. The LDCs should also address the matter of enforcement in any tariff, developed in consultation with customers, marketers or brokers, submitted in adherence to this section.

 (b)  Demonstration of fitness to deliver gas. Gas suppliers that wish to deliver gas to retail customers should demonstrate that they have the requisite financial and technical fitness to meet their obligations to customers consistent with the public interest in system reliability and LDC’s underlying supplier-of-last-resort obligation. The financial and technical fitness is expected for any marketer or broker that wants to serve any or all retail commercial, industrial or retail classes. Financial and technical fitness is aimed at ensuring that a marketer or broker has the requisite ability to offer service to the public.

 (c)  Nondiscriminatory transportation tariff rules. The LDCs may offer nondiscriminatory transportation tariff rules, developed in consultation with marketers or brokers, governing the qualifications of marketers and brokers. The rules should be consistent with any registration requirements for marketers and brokers of the Federal Energy Regulatory Commission. The tariff rules should address the following:

     (i)   Financial fitness, including the ability to comply with any penalties stemming from nonperformance or in response to changed circumstances.

     (ii)   Operational fitness, including the ability of the firm to meet peak demand of contracted customers which could be met by a showing of sufficient gas reserves or sufficient supply and capacity to meet the maximum daily delivery obligations with sufficient emergency back up supplies.

   (2)  The information expected by this section should be as generic as possible and be limited to the information needed for system reliability and performance of an LDC’s supplier-of-last-resort obligations. The information expected by this section should avoid information wanted solely or largely for an LDC’s merchant function. The information expected by this section should avoid mandating the disclosure of specific and commercially sensitive information such as price, origin, destination, and the like. Information provided to an LDC as part of its system reliability and supplier-of-last-resort obligations may not be provided to an LDC’s affiliate as part an LDC’s merchant operations.

   The provisions of this §  69.195 adopted August 15, 1997, effective August 16, 1997, 27 Pa.B. 4109.

POLICY STATEMENT ON NUCLEAR FUEL
PROCUREMENT GUIDELINES

§ 69.201. General.

 (a)  Since 66 Pa.C.S. §  1307 (relating to sliding scale of rates; adjustments) enables a utility to collect certain fuel costs on a dollar-for-dollar basis from its ratepayers, a utility has the highest degree of responsibility to take aggressive action on behalf of its ratepayers to control nuclear fuel costs. A utility should use every means reasonably available to monitor and enforce vendor adherence to all aspects of nuclear fuel procurement agreements. In addition to contract adherence, the Pennsylvania Public Utility Commission (Commission) may exercise its independent right to review each utility’s purchasing practices, which may include a review to determine if the utility is actively making every effort to secure competitive sources for every phase of the nuclear fuel cycle and is obtaining its nuclear fuel at the lowest reasonable cost. The Commission defines ‘‘lowest reasonable cost,’’ relating to nuclear fuel procurement, as contracting for or purchasing nuclear fuel at the lowest available price without sacrificing dependability or quality of service. The Commission may make constructive suggestions with regard to an individual company’s nuclear fuel procurement policies and procedures from time to time. As the process of acquiring nuclear fuel is somewhat more complex than fossil fuel, an explanation has been included to describe in general terms the elements of the nuclear fuel procurement process.

 (b)  The purpose of § §  69.202—69.206 is to establish guidelines that the Commission recommends an electric utility follow in its nuclear fuel procurement activities. The Commission realizes that nuclear fuel procurement policies of utilities may differ depending on individual circumstances. The Commission believes that there are certain common practices that will result in the lowest rea

   sonable nuclear fuel costs. Nuclear fuel procurement should be consistent with regulatory requirements, and may or may not result in the lowest priced nuclear fuel.

 (c)  If a utility believes that a nuclear fuel procurement policy that differs from that described in § §  69.202—69.206 will, in the long term, result in lower costs, the utility should submit the details of the policy for review by the Commission prior to implementation.

 (d)  If it appears through Commission review, that nuclear fuel procurement practices which differ from those described in this section and § §  69.202—69.207 have resulted in unreasonable nuclear fuel costs, a utility may be requested by the Commission to demonstrate the reasonableness of the costs.

 (e)  If the Commission determines after notice and hearing that a utility’s nuclear fuel procurement practices which differ from those described in this section and § §  69.202—69.207 have resulted in unreasonable nuclear fuel costs, the utility will be required to apply credits against the applicable energy cost rate or to make refunds to its customers.

 (f)  Specifications for the procurement of nuclear fuel should not be set at quantity levels which would preclude competitive proposals from reliable and competent suppliers. Investigations should be conducted to insure that potential vendors have adequate owned or contracted supplies to fulfill all contract provisions.

 (g)  Sections 69.202—69.206 represent the standard by which the Commission intends to assess the reasonableness of a utility’s nuclear fuel purchasing policies and practices. Sections 69.202—69.206 serve as notice to electric utilities of the Commission’s expectations with regard to nuclear fuel procurement policies and practices. Utilities should apply § §  69.202—69.206 prospectively in planning nuclear fuel purchases. If provisions of existing contracts are in conflict with § §  69.202—69.206, utilities need not seek to immediately amend the contracts, but should move towards the policies in § §  69.202—69.206 as contracts are modified, renegotiated or extended. Prior imprudent activities are not deemed to be exonerated with the promulgation of this section.

   The provisions of this §  69.201 adopted March 29, 1991, effective May 30, 1991, 21 Pa.B. 1331.

 (a)  A utility should maintain an appropriate staff to adequately fulfill its responsibility to procure nuclear fuel at the lowest reasonable cost. The utility should be prepared to solicit and handle competent bids and investigate these potential sources for ability to fulfill contracts.

 (b)  A utility should have a detailed organization chart of the personnel involved in nuclear fuel procurement, with a key official designated to act as liaison with the Commission. A utility should maintain written job descriptions for personnel, as well as formal policies and procedures pertaining to the nuclear fuel procurement process. These should be retained by the utility in the event of Pennsylvania Public Utility Commission review.

 (c)  Utility personnel in a position to influence nuclear fuel procurement decisions should be prohibited from having either direct or indirect ties or affiliations with the utility’s nuclear fuel suppliers. A utility should take appropriate steps to ensure that personnel making procurement decisions have no conflicting interests or affiliations, or the appearance of conflict.

   The provisions of this §  69.202 adopted March 29, 1991, effective May 30, 1991, 21 Pa.B. 1331.

 (a)  A utility’s nuclear fuel strategy should keep abreast of technological improvements which would provide reliable fuel at the lowest reasonable cost with maximum flexibility.

 (b)  A utility should maintain a written nuclear fuel procurement and management plan. The plan should include consideration of overall procurement goals as well as the procurement and overall fuel management strategies established to achieve those goals. Specific strategic elements to be considered include supply reliability, inventory management, competitive bidding, the use of multiple suppliers, contracting practices, and the like.

   The provisions of this §  69.203 adopted March 29, 1991, effective May 30, 1991, 21 Pa.B. 1331.

 (a)  A utility should have a written policy setting forth economic and other conditions under which different methods of financing—leasing or owning—nuclear fuel should be utilized.

 (b)  A utility should perform an economic analysis in conjunction with nuclear fuel financings. The analysis should include a study of financing costs for owning versus leasing nuclear fuel and the impact on the utility’s overall revenue requirements under both alternatives. The method of rate recovery of nuclear fuel costs should not be a primary factor when deciding to own or lease nuclear fuel.

 (c)  A utility should document the economic analyses required to comply with this section. These documents should be retained by the utility in accordance with the Federal Energy Regulatory Commission’s Record Retention Table and made available in the event of Pennsylvania Public Utility Commission’s review.

   The provisions of this §  69.204 adopted March 29, 1991, effective May 30, 1991, 21 Pa.B. 1331.

 (a)  General guidelines. The Pennsylvania Public Utility Commission (Commission) recommends that a utility adopt the following general nuclear fuel purchasing guidelines:

   (1)  A balance of long-term, short-term and spot purchases should be utilized if possible and economic to maximize the utility’s flexibility in its nuclear fuel procurement practices. This balance can provide a reasonably stable supply while allowing the utility the option of taking advantage of changing market conditions.

   (2)  Suppliers should be selected on the basis of the best evaluated bid, as collectively determined from reliability, quality of service and pricing considerations. A utility should use its own staff in seeking and qualifying adequate nuclear fuel suppliers and should minimize the use of brokers, except if the use of brokers is consistent with the basic nuclear fuel procurement policy of obtaining nuclear fuel at the lowest reasonable price.

   (3)  A utility should maintain documentation of reasons for selection of any bid on file in accordance with the Federal Energy Regulatory Commission’s Record Retention Table. Commission staff may inspect this documentation as deemed necessary.

   (4)  A utility should actively seek and maintain a reasonable number of acceptable suppliers from which to solicit bids. This supplier list should be updated frequently.

   (5)  Utilities should consider sealed bids on large orders.

   (6)  A utility’s verbal agreements, including telephone conversations relating to nuclear fuel price and quantity, should be formalized by letter or log confirming details of the agreement.

 (b)  Long term contracts.

   (1)  Price escalation clauses included in long-term contracts should be based on measurable supplier costs or on regularly published relevant indices.

   (2)  A utility should seek contracts with broad ranges in minimum/maximum quantity deliverables to be exercised at the utility’s discretion. Contract quantities could increase or decrease at the utility’s discretion based upon market conditions and contractor’s performance. The contracts could also provide a means of control over suppliers whose pricing has become noncompetitive due to changes in market conditions.

   (3)  Right to audit clauses should be included in long-term contracts that provide for price escalation based on cost. The right to audit clause gives the utility the authority to audit specific records of its suppliers. It is recommended that the utility enforce the right to audit provisions either through the use of qualified internal audit staff or outside independent auditors on a regular basis. Contracts should contain resumption clauses to provide for continuation, at the utility’s discretion, of contracts that are temporarily curtailed. The Commission may review the audit reports of long-term contracts of nuclear fuel and conduct reexaminations of the utility as considered necessary.

   (4)  It is recommended that contracts, escalation clauses or terms of purchase of nuclear fuel agreements be reviewed by the legal counsel for the utility. Contracts should include specific reference to special arrangements, such as financial loan agreements, which may affect the operation of the utility or the price of nuclear fuel.

   (5)  A utility should regularly compare the price of nuclear fuel (U₃O₈) from its sources to that available for similar sources in the competitive market place. A utility may be called upon to explain why its U₃O₈ prices differ significantly from those published for similar competitive markets. The Commission may take appropriate action upon discovery of significant differences for an extended period. Decisions on the reasonableness of a utility’s deviation from the respective published prices will be made by the Commission on a case-by-case basis.

   (6)  This section, § §  69.201—69.204, 69.206 and 69.207 also apply to wholly-owned nuclear fuel sources.

 (c)  Dedicated nuclear fuel supplies. Dedicated nuclear fuel supplies are those in which a utility, through ownership, contract quantity requirements or guarantee of debt, has substantial influence and interest in the contracted nuclear fuel supply. The following guidelines are recommended for dedicated nuclear fuel supplies:

   (1)  To insure efficient management over a dedicated nuclear fuel supply, a utility should not provide, assume or guarantee an excessive amount of the project financing. The owner, operator or developer of the mine, or nuclear fuel supplier, should maintain substantial equity in the project or guarantee a substantial portion of the project financing.

   (2)  The use of cost-plus contracts is strongly discouraged unless justification can be provided that the contract is essential for assurance of supply.

   (3)  Contracts for dedicated nuclear fuel supplies should contain additional provisions so that if nuclear fuel prices exceed the range of prices from other available suppliers for nuclear fuel with similar characteristics for an extended period of time, the nuclear fuel price charged by the dedicated supplier would be adjusted to fall within the price range of the similar nuclear fuel.

   The provisions of this §  69.205 adopted March 29, 1991, effective May 30, 1991, 21 Pa.B. 1331.

 (a)  A utility should have a written policy stating its nuclear fuel inventory management objectives. The policy should include inventory target levels, ordering points or cycles, and the like.

 (b)  The term ‘‘inventory,’’ for the purpose of this section, § §  609.201—69.205 and 69.207, includes uranium in the form of U₃O₈ or natural and enriched UF₆ in process or in storage and all other uranium which is already processed but not in the reactor—for example, fabricated fuel assemblies—and held in storage.

 (c)  The inventory management objectives should be reevaluated annually for conformance with supply and demand conditions as they exist in the nuclear fuel marketplace. The written inventory management objectives should be revised if it is determined through the reevaluation process, that the objectives are not synchronized with current market conditions.

 (d)  A utility has an obligation to its ratepayers to maintain its nuclear fuel inventory at a level which achieves optimum fuel cost savings without endangering normal plant operations. When determining the proper inventory level, the use of innovative core design solutions to accommodate the unexpected loss of nuclear fuel assemblies should be considered.

 (e)  A utility will be expected to justify, for recovery purposes, the costs associated with carrying excess levels of inventory. Excess inventory levels are defined as those levels which exceed the quantity necessary to satisfy, per licensed nuclear generating unit, one standard reload in process, that is, conversion, enrichment or fabrication. Completely fabricated fuel assemblies should be held in storage no longer than 4 months before they are loaded into the reactor. The Pennsylvania Public Utility Commission (Commission) recognizes that nuclear fuel inventories in excess of the levels in this subsection are occasionally necessary and proper. The utility shall be able to cost justify the excess amounts. A demonstrable, extraordinary operational requirement or nuclear fuel market situation may provide an instance where excess inventory levels could be deemed proper.

 (f)  Pertinent data, related to this subsection, should be retained by the utility in accordance with the Federal Energy Regulatory Commission’s Record Retention Table and made available for Commission review upon request.

   The provisions of this §  69.206 adopted March 29, 1991, effective May 30, 1991, 21 Pa.B. 1331.

 (a)  The nuclear fuel procurement process consists of the following major procurement and processing steps prior to delivery of fuel bundles to the nuclear plant, where the bundles are receipt-inspected prior to insertion in the reactor.

   (1)  Mining/milling. Purchase of uranium concentrates (U₃O₈) from a supplier who processes the material as follows: After mining, the uranium ore is shipped to a milling facility which extracts uranium concentrates by a chemical leaching process. After drying and further processing, the substance consists of about 90% uranium oxide compound (U₃O₈), which is referred to as ‘‘yellow cake’’. In the nuclear fuel procurement process, the most options exist for the acquisition of ‘‘yellow cake’’ where many suppliers exist. A utility generally procures U₃O₈ (‘‘yellow cake’’) delivered to a preselected convertor.

   (2)  Conversion. The next step in the procurement process is the purchase of conversion services. Conversion is a chemical process where the U₃O₈ is further refined, impurities are extracted and in a series of additional steps the U₃O₈ is converted to natural uranium hexafluoride (UF₆). Conversion services represent a very small component of the total cost of nuclear fuel.

   (3)  Enrichment.

     (i)   Natural UF₆ is shipped to an enrichment facility where it is subjected to a process to increase the percentage of U-235 above that of the natural uranium. Enrichment is a complex, costly and energy intensive procedure.

     (ii)   Domestic facilities owned and operated by the United States Government enrich a major portion of uranium used by the worldwide commercial reactor industry. Enrichment is performed under contracts that are negotiated many years in advance of the actual work and are now typically based upon the actual reactor requirements at time of order placement.

     (iii)   New enrichment technologies are currently being developed. These technologies, if successfully demonstrated and licensed, may offer lower cost alternatives to that currently provided by the United States Government.

   (4)  Fabrication. Fabrication services usually include shipment of the enriched UF₆ to the fabricator, where it is converted to solid (UO₂) fuel pellets. The fuel pellets are loaded into hollow fuel rods made of a special zirconium alloy which are then assembled into fuel bundles for use in the reactor. Fuel assembly fabrication services have historically been provided by the manufacturer of the nuclear steam supply system. In most cases, however, other vendors are capable of performing fuel assembly services.

   (5)  Receipt/inspection. At the reactor site the fabricated fuel bundles shall be loaded, moved to the fuel floor and receipt/inspected prior to loading in the reactor in a predetermined sequence. The fuel is normally delivered 2 to 3 months before the reactor is shut down.

 (b)  The nuclear fuel procurement process for reload quantities of fuel bundles, excluding contract negotiations, from purchase of U₃O₈ through loading in the reactor normally requires between 15 months and 24 months to complete.

   The provisions of this §  69.207 adopted March 29, 1991, effective May 30, 1991, 21 Pa.B. 1331.

   This section cited in 52 Pa. Code §  69.201 (relating to general); 52 Pa. Code §  69.205 (relating to purchasing procedures); and 52 Pa. Code §  69.206 (relating to inventory management).

APPLICATION OF AMERICANS WITH DISABILITIES ACT AND UNIVERSAL ACCESSIBILITY ACT

§ 69.221. Application of accessibility and usability standards to pay telephone service providers—statement of policy.

 (a)  Background. The Pennsylvania General Assembly has enacted the act of December 20, 1988 (P. L. 1296, No. 166), known as the Universal Accessibility Act (UAA) (71 P. S. § §  1455.1—1455.3b), to provide for the accessibility and usability of public buildings to persons with disabilities. The UAA is being implemented by the Department of Labor and Industry through regulations promulgated at 34 Pa. Code Chapter 60 (relating to Universal Accessibility Standards). The United States Congress enacted the Americans With Disabilities Act of 1990 (ADA) (42 U.S.C. § §  12101—12213) to similarly provide comprehensive civil rights protections to persons with disabilities. Protections involved in the Federal legislation include accessibility and usability of public accommodations. The Federal Department of Justice has promulgated regulations at 28 CFR Part 36 (relating to non-discrimination on the basis of disability by public accommodations and in commercial facilities), implementing the ADA and has adopted standards referred to as the Americans With Disabilities Act Accessibility Guidelines for Buildings and Facilities (ADAAG). Both statutes and the underlying regulations are consistent with ADAAG and are applicable to the usability and accessibility of pay telephones in public buildings or accommodations; however, the compliance obligation is placed on the owner of the building or accommodation. While compliance with accessibility standards is under the primary control of the building owner or lessee, compliance with usability standards is clearly under the primary control of the pay telephone service provider. The Commission regulates the adequacy of service of pay telephone service providers operating in this Commonwealth under 66 Pa.C.S. §  1501 or Chapter 29 (relating to character of service and facilities; and telephone and telegraph wires). Clearly, the Commission has authority to exercise its jurisdiction over Pennsylvania pay telephone compliance with usability standards as required by the ADA as a component of adequacy of service. In this regard, the Commission finds it is in the public interest that ADAAG usability standards apply to pay telephones when compliance is required by the ADA.

 (b)  Statement of policy. The provision of legally adequate pay telephone service in this Commonwealth should include compliance with ADAAG usability standards in the following instances where compliance with usability standards is required by the ADA:

   (1)  Pay telephone service in new or altered public accommodations.

   (2)  Pay telephone service in new or existing facilities used by public entities.

   (3)  Text telephone service in stadiums, arenas, convention centers and covered shopping malls.

   (4)  Text telephone service adjacent to hospital emergency rooms, hospital recovery rooms or hospital waiting rooms.

 (c)  Compliance. The Commission intends to exercise its jurisdiction by promoting compliance with ADA requirements applicable to pay telephones and views pay telephone service providers legally responsible for usability violations.

   The provisions of this §  69.221 adopted November 18, 1994, effective November 19, 1994, 24 Pa.B. 5755.

POLICY STATEMENT ON PLAIN LANGUAGE
GUIDELINES

§ 69.251. Plain language—statement of policy.

 (a)  General. The Commission recommends that public utilities adopt the following guidelines for written material provided to residential customers. Each utility shall designate appropriately trained staff persons to serve as liaisons to the Bureau of Consumer Services regarding this policy statement. Companies shall conduct field tests, use consumer advisory panels or focus groups to prepare plain language materials for Commission review. The Bureau of Consumer Services will selectively review the materials prior to final company publication and mailing to residential customers.

   (1)  In preparing information, the utility shall include use of the following:

     (i)   Short sentences.

     (ii)   Active voice rather than passive voice.

     (iii)   Personal pronouns.

     (iv)   Definition of necessary terms that are technical and not commonly understood.

     (v)   Clear section headings which accurately describe the information that follows.

     (vi)   Separate listing of each condition of any agreement, offer or requirement.

     (vii)   Commonly understood words.

   (2)  The utility shall avoid the following practices:

     (i)   Technical, legal or utility terms not commonly understood.

     (ii)   Double negatives.

     (iii)   Abbreviations not commonly used.

     (iv)   Foreign words, except for information aimed at non-English speaking customers, or words with obsolete meanings.

 (b)  Visual guidelines. In addition to plain language, the Commission recommends that the utilities adopt the following visual guidelines for written materials provided to residential customers:

   (1)  Clear section headings which use bold face, italics, underlining or color to set them apart from the rest of the text.

   (2)  Ink that sharply contrasts with the paper.

   (3)  Spacing and margins which make materials easy to read.

   (4)  The use of both upper and lower case letters.

   (5)  The use of large typeface, at least 8 to 10 point type.

   (6)  Line length shall contain between 50 and 70 characters.

 (c)  Billing format. The billing formats shall comply with § §  56.15 and 64.14 (relating to billing information; and billing information). The Commission recommends that the company’s phone number for questions or complaints be clearly located on the bill. Plain language shall be used in the billing format as follows:

   (1)  Gas and electric utilities.

     (i)   A display of the unit price per kilowatt hour (KWH), therm, hundred cubic feet (CCF) or thousand cubic feet (MCF) in calculating charges, in addition to the total usage and charges due.

     (ii)   A bar graph displaying comparative energy use indicating whether the amount shown is actual or estimated.

     (iii)   Information regarding the average temperature during the periods under comparison.

     (iv)   Technical terms regularly displayed on the bill clearly defined, listed alphabetically and prominently located on the bill.

   (2)  Water utilities.

     (i)   Calculation and display of the unit price per gallon in addition to the total usage and charges due. This is not applicable to flat rate billing.

     (ii)   A bar graph displaying comparative water use for the preceding five quarters or for 13 months, depending on the billing period and whether the amount shown is actual or estimated. This is not applicable to flat rate billing.

     (iii)   Technical terms regularly displayed on the bill clearly defined, listed alphabetically and prominently located on the bill.

   (3)  Telephone utilities.

     (i)   Clearly separated charges for Basic, Nonbasic and Toll Services.

     (ii)   Discount time periods for local, measured telephone service clearly defined and prominently located on the bill.

     (iii)   Information directing the customer to the local exchange carrier’s discount toll rates within its directory.

     (iv)   Clear, concise billing free of redundant information with a limited number of pages.

     (v)   Billing for each interexchange carrier displayed on a separate page with the exception of alternative operator service providers. Billing for alternative operator service providers may be grouped on one or more pages. The alternative operator service should clearly be identified by company name.

     (vi)   Technical terms regularly displayed on the bill clearly defined, alphabetically listed and prominently located on the bill.

   The provisions of this §  69.251 adopted May 29, 1992, effective June 29, 1992, 22 Pa.B. 2852.

POLICY STATEMENT ON
CUSTOMER ASSISTANCE PROGRAMS

§ 69.261. General.

 CAPs are designed as alternatives to traditional collection methods for low income, payment troubled customers. Customers participating in CAPs agree to make monthly payments based on household family size and gross income. Customers make regular monthly payments, which may be for an amount that is less than the current bill for utility service, in exchange for continued provision of the service. Class A electric utilities and natural gas utilities with gross intrastate annual operating revenue in excess of $40 million should adopt the guidelines in § §  69.263—69.265 (relating to CAP development; scope of CAPs; and CAP design elements) implementing residential CAPs.

   The provisions of this §  69.261 adopted July 24, 1992, effective July 25, 1992, 22 Pa.B. 3914; amended May 7, 1999, effective May 8, 1999, 29 Pa.B. 2495. Immediately preceding text appears at serial pages (202026) and (241319).

 The following words and terms, when used in § §  69.261, 69.263—69.267 and this section, have the following meanings, unless the context clearly indicates otherwise;

   Alternative program designs—Program designs which include traditional utility collection methods, alternative collection approaches that do not include a CAP and CAP designs which substantially deviate from this chapter.

   CAP—Customer Assistance Program.

   EDC—Electric distribution company—The electric distribution company as defined in 66 Pa.C.S. §  2803 (relating to definitions).

   LIHEAP—Low Income Home Energy Assistance Program—A Federally funded program which provides financial assistance grants to needy households for home energy bills.

   Low income customers—A residential utility customer whose annual household gross income is at or below 150% of the Federal poverty income guidelines.

   Low-income payment troubled customers—Low-income customers who have failed to maintain one or more payment arrangements.

   The provisions of this §  69.262 adopted July 24, 1992, effective July 25, 1992, 22 Pa.B. 3914; amended May 7, 1999, effective May 8, 1999, 29 Pa.B. 2495. Immediately preceding text appears at serial page (241319).

 (a)  A utility should develop a CAP consistent with the guidelines provided in § §  69.261, 69.262, 69.264—69.267 and this section.

 (b)  The Bureau of Consumer Services will work with the utility in CAP development.

 (c)  Before implementing, revising or expanding a CAP, a utility should submit its CAP proposal to the Bureau of Consumer Services for review and Commission approval of design elements. This review is not for ratemaking purposes, and the rate consequences of any CAP will be addressed within the context of subsequent Commission rate proceedings as described in §  69.266 (relating to cost recovery).

   The provisions of this §  69.263 adopted July 24, 1992, effective July 25, 1992, 22 Pa.B. 3914; amended May 7, 1999, effective May 8, 1999, 29 Pa.B. 2495. Immediately preceding text appears at serial pages (241319) to (241320).

 CAPs should be targeted to low-income, payment troubled customers. The participation limit for CAP should reflect a needs assessment, consideration of the estimated number of low-income households in the utility’s service territory, the number of participants currently enrolled in the pilot CAP, participation rates for assistance programs and the resources available to meet the needs of the targeted population.

   The provisions of this §  69.264 adopted July 24, 1992, effective July 25, 1992, 22 Pa.B. 3914; amended May 7, 1999, effective May 8, 1999, 29 Pa.B. 2495. Immediately preceding text appears at serial page (241320).

 The following design elements should be included in a CAP:

   (1)  Program funding. Program funding should be derived from the following sources:

     (i)   Payments from CAP participants.

     (ii)   LIHEAP grants.

     (iii)   Operations and maintenance expense reductions.

     (iv)   Universal service funding mechanism for EDCs.

   (2)  Payment plan proposal. Generally, CAP payments for total electric and natural gas home energy should not exceed 17% of the CAP participant’s annual income. The minimum payment should not be less than the guidelines in paragraph (3)(v)(A) and (B). Payment plans should be based on one or a combination of the following:

     (i)   Percentage of income plan. Total payment for total electric and natural gas home energy under a percentage of income plan is determined based upon a scheduled percentage of the participant’s annual gross income. The participating household’s gross income and family size place the family at a particular poverty level based on Federal poverty income guidelines.

       (A)   Generally, maximum payments for electric nonheating service should be within the following ranges:

         (I)   Household income between 0—50% of poverty at 2%—5% of income.

         (II)   Household income between 51—100% of poverty at 4%—6% of income.

         (III)   Household income between 101—150% of poverty at 6%—7% of income.

       (B)   Generally, maximum payments for gas heating should be within the following ranges:

         (I)   Household income between 0—50% of poverty at 5%—8% of income.

         (II)   Household income between 51—100% of poverty at 7%—10% of income.

         (III)   Household income between 101—150% of poverty at 9%—10% of income.

       (C)   Generally, maximum payments for electric heating or gas heating and electric nonheating combined should not exceed the following guidelines:

         (I)   Household income between 0—50% of poverty at 7%—13% of income.

         (II)   Household income between 51—100% of poverty at 11%—16% of income.

         (III)   Household income between 101—150% of poverty at 15%—17% of income.

     (ii)   Percentage of bill plan. The participant’s household payment contribution for total electric and natural gas home energy under a percentage of bill plan is determined using variables based on family size and income and the household’s energy usage level. A participant’s annual payment is calculated as a percentage of income payment and converted to a percentage of the annual bill. When a utility determines subsequent CAP payment amounts, a participant will continue to pay the same percentage of the total bill even if annual usage has changed.

     (iii)   Rate discount. The participant’s energy usage is billed at a reduced rate.

     (iv)   Minimum monthly payment. The participant’s payment contribution is calculated by taking the participant’s estimated monthly budget billing amount and subtracting the maximum, monthly CAP credit (previously called billing deficiency).

     (v)   Annualized, average payment. The participant’s payment contribution is calculated by determining the total amount the participant paid over the last 12 months and dividing by 12 months to determine a monthly budget.

     (vi)   An alternative payment formula. An alternative payment formula must be reviewed by the Bureau of Consumer Services and approved by the Commission.

   (3)  Control features. The utility should include the following control features to limit program costs:

     (i)   Minimum payment terms.

       (A)   A CAP participant payment for a gas heating account should be at least $18—$25 a month.

       (B)   A CAP participant payment for a nonheating account should be at least $12—$15 a month.

       (C)   A CAP participant payment for an electric heating account should be at least $30—$40 a month.

     (ii)   Nonbasic services. A CAP participant may not subscribe to nonbasic services that would cause an increase in monthly billing and would not contribute to bill reduction. Nonbasic services that help to reduce bills may be allowable. CAP credits should not be used to pay for nonbasic services.

     (iii)   Consumption limits. Limits on consumption should be set at a percentage of a participant’s historical average usage. A level of 110% is recommended. Adjustments in consumption should be made for extreme weather conditions through the use of weather normalization techniques.

     (iv)   High usage treatment. Utilities should target for special treatment those participants who historically use high amounts of energy.

     (v)   Maximum CAP credits. The annual maximum CAP credits should not exceed a total of $1,400 per participant.

       (A)   The annual maximum CAP credits per gas heating participant should not exceed $840.

       (B)   The annual maximum CAP credits per nonheating customer should not exceed $560.

       (C)   The annual maximum CAP credits per electric heating participant should not exceed $1,400.

     (vi)   Exemptions. A utility may exempt a household from a CAP control feature if one or more of the following conditions exist:

       (A)   The household experienced the addition of a family member.

       (B)   A member of the household experienced a serious illness.

       (C)   Energy consumption was beyond the household’s ability to control.

       (D)   The household is located in housing that is or has been condemned or has housing code violations that negatively affect energy consumption.

       (E)   Energy consumption estimates have been based on consumption of a previous occupant.

   (4)  Eligibility criteria. The CAP applicant should meet the following criteria for eligibility:

     (i)   Status as a utility ratepayer or new applicant for service is verified.

     (ii)   Household income is verified at or below 150% of the Federal poverty income guidelines.

     (iii)   The applicant is a low income, payment troubled customer. When determining if a CAP applicant is payment troubled, a utility should select one of the following four options to prioritize the enrollment of eligible, payment troubled customers:

       (A)   A household whose housing and utility costs exceed 45% of the household’s total income. Housing and utility costs are defined as rent or mortgage/taxes and gas, electric, water, oil, telephone and sewage.

       (B)   A household who has $100 or less disposable income after subtracting all household expenses from all household income.

       (C)   A household who has an arrearage. The utility may define the amount of the arrearage.

       (D)   A household who has received a termination notice or who has failed to maintain one payment arrangement.

   (5)  Appeal process. The utility should establish the following appeal process for program denial:

     (i)   If the CAP applicant is not satisfied with the utility’s initial eligibility determination, the utility should use utility company dispute procedures in § §  56.151 and 56.152 (relating to general rule; and contents of the utility company report).

     (ii)   The CAP applicant may appeal the denial of eligibility to the Bureau of Consumer Services in accordance with § §  56.161—56.165 (relating to informal complaint procedures).

   (6)  Administration. If feasible, the utility should include nonprofit community based organizations in the operation of the CAP. The utility should incorporate the following components into the CAP administration:

     (i)   Outreach. Outreach may be conducted by nonprofit, community-based organizations and should be targeted to low income payment troubled customers. The utility should make automatic referrals to CAP when a low-income customer calls to make payment arrangements.

     (ii)   Intake and verification. Income verification may be completed through a certification process that is satisfactory to the utility or certification through a government agency. Intake may also be conducted by those organizations and should include verification of the following:

       (A)   Identification of the CAP applicant.

       (B)   The annual household income.

       (C)   The family size.

       (D)   The ratepayer status.

       (E)   The class of service—heating or nonheating.

     (iii)   Calculation of payment. Calculation of the monthly CAP payment should be the responsibility of the utility. The utility may develop a payment chart so that the assisting community-based organizations may determine payment amounts during the intake interview.

     (iv)   Explanation of CAP. A complete and thorough explanation of the CAP components should be provided to participants.

     (v)   Application for LIHEAP grants. An application for LIHEAP grants, to the extent that is available, should be completed during the intake interview.

     (vi)   Consumer education and referral. CAP consumer education programs should include information on benefits and responsibilities of CAP participation and the importance of energy conservation. Referrals to other appropriate support services should also be a part of consumer education.

     (vii)   Account monitoring. Account monitoring should include both payment and energy consumption monitoring.

     (viii)   Annual reapplication. An annual process that reestablishes a participant’s eligibility for CAP benefits should be required.

     (ix)   Arrearage forgiveness. Arrearage forgiveness should occur over a 2- to 3-year period contingent upon receipt of regular monthly payments by the CAP participant.

     (x)   Routine management program progress reports. Progress reports that may be used to monitor CAP administration should be prepared at regular intervals. These reports should include basic information related to the number of participants, payments and account status.

   (7)  Default provisions. The failure of a participant to comply with one of the following should result in dismissal from CAP participation:

     (i)   Failure to make payments will result in the utility returning the participant to the regular collection cycle and may lead to termination of service. By returning the customer to the regular collection cycle, the utility does not need to enter into a new payment arrangement but may begin the termination process. At a minimum, the utility should inform the participant of the consequences of defaulting from the CAP. To avoid termination of service, the CAP participant must pay the amount set forth in the termination notice prior to the scheduled termination date. This amount should generally be no more than two CAP bills.

     (ii)   Failure to abide by established consumption limits.

     (iii)   Failure to allow access or to provide customer meter readings in 4 consecutive months.

     (iv)   Failure to report changes in income or family size.

     (v)   Failure to accept budget counseling, weatherization/usage reduction or consumer education services.

     (vi)   Failure to annually verify eligibility.

   (8)  Reinstatement policy. A customer may be reinstated into CAP at the utility’s discretion.

   (9)  Coordination of energy assistance benefits. In a CAP, the utility should include the following to coordinate a participant’s energy assistance benefits between it and other utilities:

     (i)   A LIHEAP grant should be designated by the participant to the utility sponsoring the CAP.

     (ii)   A utility may impose a penalty on a CAP participant who is eligible for LIHEAP benefits but who fails to apply for those benefits. A utility should use this option carefully and the penalty should not exceed the amount of an average LIHEAP cash benefit. If a customer applies for a LIHEAP benefit but directs it to another utility or energy provider, the CAP provider should not assess a penalty.

     (iii)   The LIHEAP grant should be applied to reduce the amount of CAP credits.

     (iv)   A utility may impose a penalty on a CAP participant who is eligible for LIHEAP benefits but who fails to apply for those benefits. A utility should use this option carefully and the penalty should not exceed the amount of an average LIHEAP cash benefit. If a customer applies for a LIHEAP benefit but directs it to another utility or energy provider, the CAP provider should not assess a penalty.

   (10)  Evaluation. The utility should thoroughly and objectively evaluate its CAP in accordance with the following unless otherwise modified in §  54.76 (relating to evaluation reporting requirements).

     (i)   Content. The evaluation should include both process and impact components. The process evaluation should focus on whether CAP implementation conforms to the program design and should assess the degree to which the program operates efficiently. The impact evaluation should focus on the degree to which the program achieves the continuation of utility service to CAP participants at reasonable cost levels. The impact evaluation should include an analysis of the following:

       (A)   Customer payment behavior.

       (B)   Energy assistance participation.

       (C)   Energy consumption.

       (D)   Administrative costs.

       (E)   Program costs.

     (ii)   Time frame. Unless otherwise modified by §  54.76, the time frame for evaluations should be as follows:

       (A)   Following the expansion of a CAP or subsequent to substantial revision of an existing CAP or alternate program design, a one-time process evaluation completed by an independent third-party should be undertaken during the middle of the second year.

       (B)   Program impacts should be evaluated by an independent third-party at no more than 6 year intervals and submitted to the Commission.

     (iii)   Evaluation plan approval. The utility should submit the impact evaluation plan to the Bureau of Consumer Services for review and approval.

   The provisions of this §  69.265 adopted July 24, 1992, effective July 25, 1992, 22 Pa.B. 3914; amended May 7, 1999, effective May 8, 1999, 29 Pa.B. 2495; amended May 7, 2010, effective May 8, 2010, 40 Pa.B. 2443. Immediately preceding text appears at serial pages (255453) to (255460).

 In evaluating utility CAPs for ratemaking purposes, the Commission will consider both revenue and expense impacts. Revenue impact considerations include a comparison between the amount of revenue collected from CAP participants prior to and during their enrollment in the CAP. CAP expense impacts include both the expenses associated with operating the CAPs as well as the potential decrease of customary utility operating expenses. Operating expenses include the return requirement on cash working capital for carrying arrearages, the cost of credit and collection activities for dealing with low income negative ability to pay customers and uncollectible accounts expense for writing off bad debt for these customers. When making CAP-related expense adjustments and projections, utilities should indicate whether a customer’s participation in a CAP produced an immediate reduction in customary utility expenses and a reduction in future customary expenses pertaining to that account.

   The provisions of this §  69.266 adopted July 24, 1992, effective July 25, 1992, 22 Pa.B. 3914.

 Alternative program designs that differ from § §  69.261—69.266 and this section may reduce uncollectible balances and may provide low income, payment troubled customers with needed assistance. These programs may be acceptable if the utility can provide support for design deviations. Before implementing an alternative program design, the utility should submit its proposal including an evaluation plan as described in §  69.265(10) (relating to CAP design elements) to the Bureau of Consumer Services for review and Commission approval.

   The provisions of this §  69.267 adopted July 24, 1992, effective July 25, 1992, 22 Pa.B. 3914; amended May 7, 1999, effective May 8, 1999, 29 Pa.B. 2495. Immediately preceding text appears at serial pages (202033) to (202034).

   This section cited in 52 Pa. Code §  69.262 (relating to definitions); and 52 Pa. Code §  69.263 (relating to CAP development).

CLEAN AIR ACT EMISSIONS ALLOWANCES

§ 69.291. General.

 Electric utilities are subject to stringent emission reduction requirements under section 401 of the Clean Air Act Amendments of 1990 (CAAA) (42 U.S.C.A. §  7651). An innovative market-based system for the trading of allowances for the emission of sulfur dioxide was established under the CAAA in order to substantially reduce the cost of compliance with the Clean Air Act (See 42 U.S.C.A. §  7651b(b)). Because of the importance of allowance trading to the cost-effective implementation of the CAAA, the Commission promulgated the guidelines in this section and § §  69.292—69.294 to help facilitate a liquid allowance trading market.

   The provisions of this §  69.291 adopted February 26, 1993, effective February 27, 1993, 23 Pa.B. 972.

 The following words and terms, when used in §  69.291, this section and § §  69.293 and 69.294, have the following meanings, unless the context clearly indicates otherwise:

   Allowance—An authorization, allocated to an affected utility by the Administrator of the United States Environmental Protection Agency or the Administrator’s authorized representative to emit up to 1 ton of sulfur dioxide during a specified calendar year.

   Allowance futures—The negotiation of agreements among parties for the sale and purchase of allowances sometime in the future.

   Allowance options—A contract that conveys the right but not the obligation, to buy or sell allowances at a certain price for a limited time. Only the seller of the option is obligated to perform.

   Allowance pool—An agreement by two or more utilities whereby the allocation of allowances is divided among the pool members.

   Banked allowances—Allowances held in reserve for future use.

   Below-the-line—Revenues and expenses that are not associated with utility operations and which are not used to establish rates.

   Clean Air Act Compliance Plans—With regard to the 1990 Clean Air Act Amendments, this term refers to actions which a utility plans, prepared incompliance with 66 Pa.C.S. §  530 (relating to Clean Air Act implementation plans), to reduce SO₂ emissions.

   The provisions of this §  69.292 adopted February 26, 1993, effective February 27, 1993, 23 Pa.B. 972.

 (a)  Approval of compliance plans.

   (1)  The Commission will, upon request, review a jurisdictional utility’s proposed CAAA compliance plan under 66 Pa.C.S. §  530 (relating to Clean Air Act implementation plans), including planned sales or purchases of emission allowances. Absent special circumstances, the Commission will not approve specific transactions. A proposed plan shall detail the analysis used by the utility to derive its plan and the alternatives considered with enough specificity to permit reasonable evaluation. In addition, the Commission may require that companies supply specific information to support these plans.

   (2)  If a utility chooses not to have its compliance plan approved, the plan will only be reviewed in the context of a subsequent base rate or other proceeding in which that utility seeks recovery of its compliance costs.

   (3)  Public utilities are not required to obtain certificates of public convenience under 66 Pa.C.S. §  1102 (relating to enumeration of acts requiring certificate) to engage in emissions allowances transactions.

   (4)  Emissions allowances transactions, including the purchase and sale of emissions allowances, allowance options and future contracts, do not constitute the issuance or assumption of securities within the meaning of 66 Pa.C.S. §  1901(b) and (c) (relating to registration of securities to be issued or assumed) and therefore no registration of a securities certificate is required.

 (b)  Banking.

   (1)  A utility may bank some level of emission allowances to prepare for unforeseen future contingencies. The Commission will not set generic or benchmark reserve levels or benchmark prices. The determination of an appropriate number of banked allowances will depend upon a utility’s specific circumstances. The utility has the burden of proof concerning the appropriate number of banked allowances. The Commission will view a utility’s decision to bank allowances as a part of its overall compliance plan. Approval of a utility’s decision to bank allowances does not assure a prudency finding for purposes of ratemaking.

   (2)  The Commission finds it inappropriate to adopt a categorical approach to reserve allowances because individual utility circumstances will differ. Operating contingency allowance reserves, determined to be prudent, will be granted appropriate ratemaking treatment in base rate proceedings under §  69.294(b) (relating to ratemaking treatment of emission allowances).

 (c)  Pooling arrangements. The Commission recognizes that pooling arrangements which are consistent with section 405 of the Clean Air Act Amendments of 1990 (42 U.S.C.A. §  651d) may be appropriate. Pooling options will be reviewed by the Commission as part of the compliance plan review process.

 (d)  Sales of allowances to nonutility generators. The Commission will not require allowance preferences for the sale of emissions allowances to nonutility generating facilities, such as qualifying facilities, independent power producers and exempt wholesale generators.

   The provisions of this §  69.293 adopted February 26, 1993, effective February 27, 1993, 23 Pa.B. 972.

 (a)  Valuation. Emission allowances will be valued at original costs for ratemaking purposes. Allowances allocated by the Environment Protection Agency have a ‘‘zero’’ cost; while purchased allowances will be valued at their full purchase price inclusive of broker fees or at fair market value if purchased as part of equipment, fuel or power-purchase transactions.

 (b)  Ratemaking treatment. Emissions allowances will be treated as fuel inventory for ratemaking purposes and will be included in the rate base consistent with the Commission’s practice for operating inventory items. Allowances in inventory will earn a return in the same way as other rate base investments.

 (c)  Energy cost rate treatment. Emission allowances are energy-related power production expenses during the period in which they are used. Allowances may be recoverable through the utility’s energy cost rate (ECR). Gains or losses on emissions allowance transactions will be flowed through to customers in the ECR on an energy (KWH) basis unless the gains or losses are related to nonutility expenses or investments and are recorded below-the-line.

   The provisions of this §  69.294 adopted February 26, 1993, effective February 27, 1993, 23 Pa.B. 972.

   The provisions of this §  69.311 adopted April 30, 1993, effective May 1, 1993, 23 Pa.B. 2150; reserved August 9, 1996, effective August 10, 1996, 26 Pa.B. 3851. Immediately preceding text appears at serial page (202037).

PUBLIC INPUT HEARINGS IN RATE PROCEEDINGS

§ 69.321. Public input hearings in rate proceedings—statement of policy.

 (a)  Prior to the holding of an initial hearing in a rate case, information received by the Commission indicating public concern shall be directed to the Bureau of Consumer Services of the Commission. This information will be made available to the Office of Administrative Law Judge.

 (b)  If the Commission determines that substantial public interest in a rate proceeding has been shown, at least one public input hearing will be held in the utility’s service area.

 (c)  To allow an opportunity for the complete airing of concerns expressed or issues raised by consumers, public input sessions should be held as early as is practical during the course of the proceeding.

 (d)  At the start of each public input hearing, the presiding officer will provide a short, clear and specific statement describing the ratemaking process; the history of the particular case to date; future progress of the case; and an explanation of the following consumers’ options at the hearing:

   (1)  To testify formally in the case, upon oath or affirmation, and be subject to cross-examination.

   (2)  To make unsworn or unaffirmed statements at the hearing. These statements may be ‘‘off the record’’ and will not be subject to cross-examination, will not be transcribed by the court stenographer and will not be considered by the presiding officer in the recommended decision.

   (3)  Not to testify at the public input session but to provide information to the Commission’s Office of Trial Staff attorney assigned to the case, the Consumer Advocate and the Small Business Advocate for possible use by them in the hearings at their discretion.

 (e)  On-the-record testimony, to the extent it is relevant, material and competent, will be considered as evidence by the presiding officer and the Commission, subject to the customary rules of procedure and evidence.

 (f)  The presiding officer will make every attempt to give consumers full opportunity to provide input into the case.

 (g)  At least one representative from the Commission should be present at each public input session to deal with individual service problems a consumer may have with the utility.

 (h)  Utilities will be encouraged to provide representatives to answer questions consumers may have with respect to the pending case.

 (i)  If the actions of a participant in a public input session are determined by the presiding officer to be obstructive to the orderly conduct of the proceedings and adverse to the public interest, the presiding officer may adjourn or continue the public input session.

   The provisions of this §  69.321 adopted April 4, 1997, effective April 5, 1997, 27 Pa.B. 1658.

RECOVERY OF FERC ORDER 636 TRANSITION
COSTS—STATEMENT OF POLICY

§ 69.341. Recovery of transition costs.

 (a)  On April 8, 1992, the Federal Energy Regulatory Commission (FERC) issued its Final Rule in Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 284 of the Commission’s Regulations (Docket No. RM91-11-000); and Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol (Docket No. RM87-34-065).

 (b)  FERC recognized that to implement the requirements of the new rules, the pipelines would likely incur certain costs. The costs to effectuate the restructuring have been generically referred to as ‘‘transition’’ costs.

   (1)  FERC Account 191 transition costs are costs which shall be considered as ‘‘natural gas’’ costs within the meaning of that term as used in 66 Pa.C.S. §  1307(f) (relating to sliding scale of rates; adjustments). Consequently, FERC Account 191 transition costs may be presented as a claim in the purchased gas cost proceedings of local gas distribution companies (LDCs) subject to the statutory and regulatory procedures applicable to gas cost rate proceedings, generally. See National Fuel Gas Distribution Corporation v. Pennsylvania Public Utility Commission, 137 Pa. Commw. 621, 587 A.2d 54 (1991).

   (2)  The Commission concludes that transition costs in the nature of Gas Supply Realignment Costs (GSR costs) are not natural gas costs for purposes of recovery under 66 Pa.C.S. §  1307(f).

   (3)  The Commission concludes that transition costs in the nature of ‘‘stranded costs’’ are not natural gas costs subject to recovery under 66 Pa.C.S. §  1307(f).

   (4)  The Commission concludes that costs related to new facilities to implement FERC restructuring brought about by FERC Order 636 may be natural gas costs subject to recovery through gas cost rate procedures.

   (5)  The Commission will permit LDCs the opportunity for the full recovery of transition costs in the nature of GSR costs and stranded costs through the filing of a tariff or tariff supplement under 66 Pa.C.S. §  1307(a) or §  1308 (relating to voluntary changes in rates). Each filing will be evaluated on a case-by-case basis.

 (a)  The implementation of Federal Energy Regulatory Commission’s (FERC) Order No. 636 changes the environment in which the natural gas industry operates. While interstate pipeline sales gas has played an increasingly diminishing role within Pennsylvania local distribution company (LDC) supply portfolios in the years following FERC Order No. 436, Order No. 636 has now totally ‘‘unbundled’’ the services provided by interstate pipelines and they no longer provide a city-gate sales service to their customers. LDCs now secure gas supplies and arrange for the transportation and storage of the gas on one or more pipeline systems, as well as provide contingencies for back up supplies and services. This new environment increases the responsibility for supply, transportation and storage that LDCs manage, and each LDC’s supply portfolio shalladdress the reliability and flexibility required in replacing pipeline sales service. As a result, LDC fuel procurement strategies shall adapt to reflect this change.

 (b)  The Commission’s procurement review process will factor in this change. Each LDC should have as an objective the achievement of optimum burner tip rates favorable to retail customers consistent with customer demand requirements. In this regard, attention shall be given to gas supply costs associated with retail service.

 (c)  The Commission encourages LDCs to build effective and diverse supply portfolios in order to continue providing consumers with reliable service at reasonable prices under the Commission’s least cost fuel procurement criteria. These portfolios should include an optimum mix of suppliers, production areas, transporting pipelines, storage options and contract terms that may include varying pricing mechanisms, contract lengths and flexibility in quantities of gas taken. The Commission recognizes fixed prices, storage carrying costs, hedging costs and other pricing mechanisms not directly tied to the spot market,in addition to spot market pricing, as acceptable tools in developing a portfolio and a cost of gas, under the Commission’s least cost fuel procurement criteria. The Commission also recognizes a comparison of gas supplies priced, as delivered, to the LDC’s city gate as a useful tool in evaluating purchase options when an LDC considers renewing a contract for capacity on interstate gas pipeline or when it considers purchasing additional capacity. A comparison is consistent with a least cost fuel procurement as mandated by 66 Pa.C.S. § §  1307(f), 1317 and 1318 (relating to sliding scale of rates; adjustments; regulation of natural gas costs; and determination of just and reasonable natural gas rates). Furthermore, the Commission recognizes that each LDC’s service area and customer base is unique and, therefore, LDC supply portfolios will differ.

 (a)  The Commission encourages its jurisdictional local distribution companies (LDCs) to efficiently utilize interstate pipeline capacity as a valuable resource for those retail and transportation customers desirous of the capacity. The Pennsylvania LDCs should strive to utilize interstate pipeline capacity as efficiently as possible and to assist in the development of a competitive natural gas market including efficient capacity release programs. With the advent of Federal Energy Regulatory Commission (FERC) Order No. 636, the Commission encourages the LDCs to do the following:

   (1)  Engage in integrated resource planning to acquire and maintain adequate levels of interstate pipeline capacity to serve the anticipated firm requirements desired by its retail and transportation customers.

   (2)  To the fullest extent legally permissible under FERC Rules and Regulations, maintain the LDC’s contractual rights to necessary interstate pipeline capacity while mitigating the costs associated with the capacity through marketable assignments, brokering arrangements, capacity sharing arrangements, prearranged deals and buy/sell transactions.

   (3)  Seek to improve capacity utilization on a year-round basis through higher load factor consumption consistent with integrated resource planning.

   (4)  Work with customers, including other energy suppliers such as electric utilities and independent power producers, through prearranged deals and capacity release to share interstate pipeline capacity consistent with integrated resource planning nondiscriminatory open access requirements and where these arrangements provide mutual benefits to Pennsylvania’s electric and gas retail and transportation customers.

   (5)  Provide nonrecallable interstate pipeline capacity releases for the periods of time—monthly or greater—when there is capacity in excess of the anticipated firm requirements desired by the LDC’s retail and transportation customers and available back to the LDC only under a State-approved curtailment program.

   (6)  Provide recallable interstate pipeline capacity releases when capacity may be available that exceeds the LDC’s short-term capacity necessary to meet the LDC’s anticipated firm requirements of its retail and transportation customers.

 (b)  To the extent practical after consideration of the items in subsection (a)(1)—(6), interested parties should assist the Commission in the development and operation of a fully functioning capacity release market for potential shippers.

 (c)  The Commission will recognize, in the context of capacity release programs, or other programs enumerated in subsection (a)(2), and developed under the guidelines in subsection (a), the principle of cost causation and ultimately assign the costs of capacity to those customers on whose behalf adequate levels of interstate pipeline capacity are either retained or obtained. The Commission will address the treatment of revenues received by the LDC from capacity release or other programs enumerated in subsection (a)(2) on a case-by-case basis.

   The provisions of this §  69.343 adopted September 23, 1994, effective October 24, 1994, 24 Pa.B. 4784.

IMPLEMENTATION OF SFAS 106

§ 69.351. Implementation of Statement of Financial Accounting Standards for Rule No. 106 (SFAS 106)—statement of policy.

 (a)  Effective with financial statements for fiscal years beginning after December 15, 1992, SFAS 106 provides the generally accepted accounting principles to be used by large companies in accounting for post-retirement benefits other than pensions (OPEBs). Up to now, companies which provided OPEBs for their employers used the pay-as-you-go (cash) basis. Each year a company would record on its books the actual cash paid for OPEBs.

 (b)  SFAS 106 operates on the premise that post-retirement benefits are a form of deferred compensation whereby an employer promises to exchange future benefits for current service. SFAS 106 requires companies to switch to the accrual method of accounting for OPEBs. As guidance to utilities wishing to implement SFAS 106, the Commission provides the following guidelines regarding the rulemaking treatment of OPEBs:

   (1)  Each jurisdictional utility which has satisfied the appropriate customer notice requirements, presented sufficient documentation to support its SFAS 106 cost estimates and presented sufficient cost containment measures, may seek formal Commission approval to record on its books a regulatory asset pursuant to SFAS 71 equal to the difference between its current rate recognition of OPEB costs and its accrued liability for the expenses under SFAS 106 subject to recovery in future rate proceedings to the extent that the costs are prudently incurred and demonstrated to be reasonable.

   (2)  The funding of a dedicated trust for the deferred amounts is not required at this time. A utility should maintain separate balance sheet accounts for both the accrued liability and the regulatory asset along with sufficient records to allow a detailed analysis of the accounts.

   (3)  The Commission intends to move jurisdictional utilities to SFAS 106 accrual accounting for ratemaking purposes within approximately 5 years and to allow the recovery in base rates of deferred amounts in approximately 20 years, to the extent that OPEB costs are prudently incurred and examined for reasonableness in a base rate proceeding prior to rate recognition.

   (4)  If the Commission, after examination, grants current rate recognition of OPEB costs exceeding the pay-as-you-go amount, the excess amount should be placed in a dedicated trust fund.

   (5)  The Commission will monitor the development of changes in OPEB costs as a result of both government policy changes and company cost containment efforts.

   The provisions of this §  69.351 adopted June 18, 1993, effective June 19, 1993, 23 Pa.B. 2839.

PENNVEST LOAN OBLIGATIONS FOR WATER AND
SEWER COMPANIES—STATEMENT OF POLICY

§ 69.361. General.

 PENNVEST loans were established to provide funding to water and wastewater companies for improvements of drinking water and wastewater treatment facilities in this Commonwealth. The Commission is required to establish expedited practices, procedures and policies to facilitate and accomplish repayment of the loan obligations. See section 14 of the PENNVEST Act (35 P. S. §  751.14). Companies with outstanding PENNVEST loans not currently reflected in rates and companies that will receive PENNVEST loans in the future are encouraged to establish under 66 Pa.C.S. §  1307(a) (relating to sliding scale of rates; adjustments) and subject to Commission approval, an automatic adjustment by means of a sliding scale of rates limited solely to the recovery of PENNVEST principal and interest obligations, instead of seeking recovery of these amounts under 66 Pa.C.S. §  1308 (relating to voluntary changes in rates) base rate filing.

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

   DEP—The Department of Environmental Protection of the Commonwealth.

   Obligations—Bonds, notes, loans or other evidences of indebtedness issued by PENNVEST.

   PENNVEST—The Pennsylvania Infrastructure Investment Authority.

   PENNVEST Act—The Pennsylvania Infrastructure Investment Authority Act (35 P. S. § §  751.1—751.20).

 (a)  Water and wastewater companies with outstanding PENNVEST obligations that have not been reflected in rates or future PENNVEST obligations, may establish under 66 Pa.C.S. §  1307(a) (relating to sliding scale of rates; adjustments) an automatic adjustment by means of a sliding scale of rates or other method limited solely to recovery of the company’s PENNVEST principal and interest obligations.

 (b)  Filings for relief under 66 Pa.C.S. §  1307(a), may occur prior to DER inspection and should be submitted to the Commission 60—90 days prior to the first anticipated principal and interest payment.

 (c)  Companies are encouraged to provide notice to customers of the request for a PENNVEST increase by means of a sliding scale of rates or other method for the automatic adjustment of rates by bill insert to begin no less than 60 days prior to the effective date.

 (d)  Rate recovery under a 66 Pa.C.S. §  1307(a) PENNVEST automatic adjustment by means of a sliding scale of rates or other method may be approved only after the receipt of the following:

   (i)  DEP inspection.

   (ii)  Final PENNVEST amortization schedule.

 (e)  When approved by the Commission, the PENNVEST obligations should be listed on customers’ bills as a separate line item. Amounts collected under the Section 1307(a) PENNVEST automatic adjustment by means of a sliding scale of rates or other method are subject to reconciliation and refund. Revenues should be listed in a separate account dedicated for PENNVEST repayment only. Commingling of funds is discouraged.

 (f)  Complaints against recovery of PENNVEST obligations under a Section 1307(a) automatic adjustment clause will be referred to the Commission’s Office of Administrative Law Judge for hearing and adjudication. The issues of used and usefulness, prudency and reasonableness of the investment will be addressed at this hearing, if necessary.

 (g)  Companies are encouraged to report the status of PENNVEST obligations in their annual reports.

 Other expenses incurred by the water company, for example, additional operating and maintenance expenses and depreciation, association with the DER-approved project, should be evaluated in a separate Section 1308 proceeding.

   The provisions of this §  69.364 adopted February 11, 1994, effective February 12, 1994, 24 Pa.B. 880.

CONSTRUCTION WORK IN PROGRESS

§ 69.371. Ratemaking treatment of construction work in progress (CWIP).

 (a)  When exercising its discretion to include in a utility’s rate base the utility’s investment in CWIP not completed and placed in public service as of the date new base rates become effective, the Commission will consider whether the CWIP projects are the following:

   (1)  Reasonably identifiable as nonrevenue producing.

   (2)  Reasonably identifiable as nonexpense reducing.

   (3)  Reasonably shown to be necessary to improve environmental conditions or safety at existing facilities, or required to convert facilities to the utilization of coal.

   (4)  Reasonably certain to be completed within the first 6 months the new base rates will be in effect.

 (b)  A CWIP project qualifies as nonrevenue producing and nonexpense reducing if any revenue generated by, or reduction in expenses resulting from, the CWIP project is passed through to customers on a current basis.

   The provisions of this §  69.371 adopted May 19, 1995, effective May 20, 1995, 25 Pa.B. 1967.

MEDIATION PROCESS

§ 69.391. General.

 (a)  The Commission encourages parties to seek negotiated settlements of contested proceedings in lieu of incurring the time, expense and uncertainty of litigation. To further promote the goal of obtaining negotiated settlements in the public interest, the Commission has adopted guidelines that offer the parties, in certain contested proceedings, the option of mediation.

 (b)  Mediation is intended to be a flexible program designed to facilitate the amicable resolution of disputes between parties. The Office of Administrative Law Judge (OALJ) manages the mediation program.

   The provisions of this §  69.391 adopted March 4, 1994, effective March 15, 1994, 24 Pa.B. 1205; corrected February 4, 2000, effective January 8, 2000, 30 Pa.B. 634. Immediately preceding text appears at serial page (261216).

 (a)  Mediation. Mediation is available to parties in all contested proceedings, or proceedings which could be contested, when the proceeding qualifies for mediation. A proceeding qualifies for mediation when mediation is deemed appropriate by the Office of Administrative Law Judge (OALJ).

 (b)  Requesting mediation.

   (1)  Parties may request mediation, prior to the commencement of a proceeding, by sending a letter request to the Mediation Coordinator of OALJ, and a copy of the request to the Secretary of the Commission.

   (2)  Parties may request mediation in their pleadings.

   (3)  Parties may request mediation during the course of a proceeding.

 (c)  Consent to use mediation process. The OALJ may notify the parties in a proceeding that mediation may be appropriate and ask whether the parties consent to use the mediation process.

 (d)  Party with the burden of proof.

   (1)  Except as otherwise directed by the Commission, there can be no mediation unless the party with the burden of proof consents to mediate.

   (2)  When the party with the burden of proof consents to mediation in proceedings subject to a statutory deadline for adjudication, that party must also agree, in writing, to extend the statutory deadline by, at least, 60 days.

 (e)  Assignment by Commission. The Commission may assign a case to the OALJ for mediation.

   The provisions of this §  69.392 adopted March 4, 1994, effective March 15, 1994, 24 Pa.B. 1205; amended May 19, 1995, effective May 30, 1995, 25 Pa.B. 1966; amended October 29, 1999, effective October 30, 1999, 29 Pa.B. 5616. Immediately preceding text appears at serial pages (241324) to (241325).

 If the Commission assigns a case for mediation, or OALJ determines that a case should go forward with mediation, OALJ will assign a mediator to the proceeding. The mediator’s role will be to facilitate settlement of the contested issues between, or among, the parties, as opposed to rendering a decision.

   The provisions of this §  69.393 adopted March 4, 1994, effective March 15, 1994, 24 Pa.B. 1205; amended October 29, 1999, effective October 30, 1999, 29 Pa.B. 5616. Immediately preceding text appears at serial page (241325).

 (a)  If the Commission assigns a case for mediation, or the Office of Administrative Law Judge (OALJ) determines that a proceeding should go forward with mediation, the parties will be notified of the time, date, and place of the mediation session, as well as the name, address, and telephone number of the mediator.

 (b)  If the OALJ determines that the proceeding should not be set for mediation, the parties will be notified of this as well as the procedure to be used in lieu of mediation.

   The provisions of this §  69.394 adopted March 4, 1994, effective March 15, 1994, 24 Pa.B. 1205; amended October 29, 1999, effective October 30, 1999, 29 Pa.B. 5616. Immediately preceding text appears at serial page (241325).

 (a)  For cases in which hearings must be commenced within 90 days, a party’s request for mediation shall be construed as a waiver of that requirement.

 (b)  The participants in a mediation proceeding must agree to abide by mediation rules and procedures established by the Office of Administrative Law Judge. Failure to abide by these rules and procedures, following commencement of mediation, could lead to the termination of the mediation.

   The provisions of this §  69.395 adopted March 4, 1994, effective March 15, 1994, 24 Pa.B. 1205; amended October 29, 1999, effective October 30, 1999, 29 Pa.B. 5616. Immediately preceding text appears at serial page (241325).

 (a)  When an agreement is reached in a formal complaint proceeding, the complaint may be withdrawn, unless otherwise provided for by law or regulation.

 (b)  When appropriate, the mediator should submit a report to an administrative law judge, or the Commission. The report will describe only the procedural background and the result of the mediation.

   The provisions of this §  69.396 adopted October 29, 1999, effective October 30, 1999, 29 Pa.B. 5616.

 To ensure maximum flexibility, the rules and procedures used in mediation are subject to modification as deemed appropriate to facilitate a resolution of a dispute.

   The provisions of this §  69.397 adopted October 29, 1999, effective October 30, 1999, 29 Pa.B. 5616.

   This section cited in 52 Pa. Code §  63.222 (relating to expedited process for resolution of migration disputes between service providers).

SETTLEMENT GUIDELINES AND PROCEDURES FOR
MAJOR RATE CASES—STATEMENT OF POLICY

§ 69.401. General.

 In the Commission’s judgment, the results achieved from a negotiated settlement or stipulation, or both, in which the interested parties have had an opportunity to participate are often preferable to those achieved at the conclusion of a fully litigated proceeding. It is also the Commission’s judgment that the public interest will benefit by the adoption of § §  69.402—69.406 and this section which establish guidelines and procedures designed to encourage full and partial settlements as well as stipulations in major section 1308(d) general rate increase cases. A partial settlement is a comprehensive resolution of all issues in which less than all interested parties have joined. A stipulation is a resolution of less than all issues in which all or less than all interested parties have joined.

 (a)  A public utility which intends to file a general rate increase request of $1 million or more should provide by letter and certificate of service 30 days advance notice of the rate filing to the following:

   (1)  The Secretary’s Bureau, the Office of Special Assistants (OSA) and the Office of Administrative Law Judge.

   (2)  The customary parties to its prior base rate proceedings, which are deemed to include the Office of Trial Staff, the Office of Consumer Advocate, the Office of Small Business Advocate, as well as any party in the utility’s last base rate proceeding who filed a brief or exceptions.

 (b)  The advance notice should contain a reasonable estimate of the amount to be sought, a brief outline of the major reasons for the increase—for example, major plant addition, significant increase in particular expenses and the like—and an identification of other major issues in the case.

 (c)  Within 20 days in advance of the anticipated general rate increase filing, the OSA will send to the customary parties a notice indicating that they should begin preparation of discovery, engage a consultant, if necessary, and assemble a team of attorneys and technicians to litigate the case.

   (1)  To facilitate the initiation of discovery, OSA will send to the utility a standard set of industry-specific data requests.

   (2)  OSA will also advise that an informal discovery conference should be scheduled by the parties approximately 60 to 65 days following the date of the filing. An informal discovery conference between the utility and the customary parties will provide for an early opportunity to review company documents and to interview company witnesses.

   The provisions of this §  69.402 adopted September 2, 1994, effective February 1, 1995, 24 Pa.B. 4485.

 (a)  The customary parties are encouraged to staff a rate filing with sufficient attorneys and technicians to quickly and effectively engage in thorough discovery within the first 60 days of the filing. This approach permits parties to prepare for the informal discovery conference. Absent good cause, the presiding Administrative Law Judge (ALJ) will restrict discovery of the utility following the informal discovery conference to specific inquiries not appropriately asked at an earlier date. Following the conference, each party should begin preparation of a litigation position to be presented by the second prehearing conference.

 (b)  A public utility which is requesting a general rate increase of $1 million or more is encouraged to file contemporaneously with its rate request, answers to a standard set of industry-specific data requests provided by the Office of Special Assistants.

   (1)  A utility which objects to any of the standard data requests may petition the presiding ALJ—or Chief ALJ if an ALJ has not been assigned to the case—for permission to depart from answering the data requests, setting forth the reasons for the request.

   (2)  Failure of the utility to file answers to the standard data requests contemporaneously with its rate filing severely impedes the settlement process. In addition to appropriate sanctions, the presiding ALJ will consider the utility’s efforts to provide timely responses to determine whether additional time for settlement negotiations should be granted. Appropriate sanctions may include postponing or cancelling the second prehearing conference contemplated in §  69.405(b) (relating to ALJ case management procedures).

   The provisions of this §  69.403 adopted September 2, 1994, effective February 1, 1995, 24 Pa.B. 4485.

 (a)  If suspension of a general rate increase of $1 million or more is appropriate, the Commission, whenever possible, will initiate the rate investigation 30 days following the filing, rather than using the full 60 days provided for by statute. However, if the Office of Special Assistants (OSA) believes it needs the full 60-day review period to determine whether a matter should be investigated, the entire period will be utilized.

 (b)  For general rate increases of less than $1 million, OSA will, during the initial 60-day review period, engage in discussions with the utility and potential complainants, as may be appropriate, to determine whether an acceptable resolution of the issues can be achieved to avoid a formal complaint and suspension of the filing. OSA will contact the parties to the utility’s last general increase rate case and consult with the Bureau of Consumer Services in an effort to identify potential complainants. Once a formal complaint is filed, OSA will terminate these discussions and proceed with preparation of a report and order for public meeting.

   The provisions of this §  69.404 adopted September 2, 1994, effective February 1, 1995, 24 Pa.B. 4485.

 (a)  Seventy to 75 days following the general rate case filing, an initial prehearing conference will be held by the presiding Administrative Law Judge (ALJ) for scheduling purposes.

   (1)  For general rate proceedings involving amounts of $1 million or more, the parties will follow the procedures for filing written testimony and scheduling hearings outlined in the Commission’s regulations, or as otherwise directed by the presiding ALJ.

   (2)  For general rate proceedings involving amounts of $1 million or less, absent good cause shown, the parties will file all written utility direct, intervenor direct, rebuttal and surrebuttal testimony sequentially. After the submission of the written testimony, one set of hearings will be held at which the witnesses are cross-examined. Requests to depart from this procedure will be submitted to the presiding ALJ—or the Chief ALJ if an ALJ has not been assigned—30 days before the prefiled testimony would otherwise be due.

 (b)  Eighty-five to ninety days following the filing, the presiding ALJ will schedule a second prehearing conference to discuss substantive issues and the potential for settlement. Prior thereto, the ALJ will advise the customary parties whether he desires litigation position summaries to be presented at the second prehearing conference or shortly thereafter for purposes of initiating settlement discussions.

   (1)  The litigation position summary should include, at a minimum, the party’s proposed stipulations of fact, adjustments to the utility’s claimed rate base, operating revenues and operating expenses, its proposed return on common equity and basis thereof, and the proposed alternative rate structure.

   (2)  A copy of the litigation position summary should be provided to each of the customary parties participating in the proceeding.

 (c)  By the date of the initial prehearing conference, the utility will advise the Chief ALJ if one or more parties believe that settlement prospects will be enhanced by having a separate settlement judge assigned for the negotiation process. In that event, the Chief ALJ will assign a settlement judge to the proceeding. Otherwise, the proceeding will operate under a one-judge system.

   (1)  When a one-judge system is used, the presiding ALJ will notify the parties regarding the scheduling of future settlement conferences and may participate in the settlement negotiations in order to promote the public interest.

   (2)  When a two-judge system is used, a second ALJ will be assigned to adjudicate the matter if no settlement is achieved. The parties will provide the first ALJ—the settlement judge—with a summary of their respective litigation and settlement positions, without prejudice to the litigation position that the party may present if settlement negotiations prove unsuccessful. These documents will be held in confidence by the settlement judge. Subsequent settlement conferences will be scheduled by the settlement judge.

 (d)  At least one public input session will be held prior to the date the settlement is filed. This permits public testimony to be considered in developing settlement parameters without delaying the time necessary to achieve a satisfactory result.

 (e)  The ALJ is encouraged to be assertive in the settlement process in cases which he believes should settle. The ALJ will be an active participant in bringing the interested parties towards a reasonable compromise.

 (f)  To provide the necessary time for a negotiated settlement to be achieved, the ALJ is authorized to provide the parties with an additional 2 weeks in the litigation schedule to conclude settlement negotiations. This 2-week period will be subtracted from the 8-week time period provided to the Commission and its staff for review of the recommended decision and exceptions.

   The provisions of this §  69.405 adopted September 2, 1994, effective February 1, 1995, 24 Pa.B. 4485.

 (a)  Objections to a settlement of the issues in a general rate increase proceeding should be filed within 10 days of the date the settlement is filed with the ALJ. The ALJ will issue a recommended decision regarding the settlement or stipulation within 21 days or less of the deadline for filing objections. Parties objecting to a proposed settlement or stipulation are encouraged to set forth facts, affidavits, argument and relevant legal analysis and, if desired, a specific request to continue to litigate. A request to litigate should be supported by appropriate information and legal argument concerning the implications of denial of a continued opportunity to litigate the matter in lieu of settlement.

 (b)  Exceptions to the ALJ’s recommended decision will be filed within 7 days after the date the recommended decision is issued. Unless otherwise permitted by the Commission, reply exceptions will not be accepted.

 (c)  If only a stipulation of certain general rate increase issues is achieved, the ALJ will provide for an expedited schedule for hearing and briefing of the non-settled issues. The Commission will also provide for an expedited schedule for the filing of exceptions and review of the ALJ’s recommended decision.

   The provisions of this §  69.406 adopted September 2, 1994, effective February 1, 1995, 24 Pa.B. 4485.

   This section cited in 52 Pa. Code §  69.401 (relating to general).

RESIDUAL RATEMAKING FOR AVERAGE SCHEDULE
TELEPHONE COMPANIES

§ 69.501. Average schedule telephone companies; residual ratemaking—statement of policy.

 (a)  Background. In lieu of employing the FCC Part 36 cost allocation manual to develop interstate revenues, expenses and investment, an average schedule telephone company uses generalized industry data to estimate its interstate costs. For intrastate ratemaking purposes, the residual ratemaking methodology assumes that the intrastate revenue requirement is equal to the company’s total revenue requirement less revenues deemed by the average schedule to be interstate.

 (b)  Treatment of costs. To determine the intrastate cost of service for average schedule telephone companies and their intrastate results of operations and return, the costs reimbursed pursuant to the National Exchange Carrier Association (NECA) average schedule tariff should be deducted from each company’s total body of costs. This would be the appropriate way to assure consistency betweenthe state/interstate cost allocation factors implicit in the use of average schedule tariffs and the state/interstate cost allocation factors based on the FCC’s Part 36 cost allocation manual.

 (c)  Policy. For average schedule telephone companies, the Commission’s current ratemaking policy and practice for financial reporting purposes will be based upon use of the residual ratemaking method. Whether or not this method will be used to set intrastate rates for any individual average schedule telephone company will be determined only after notice and opportunity to be heard in accordance with law.

   The provisions of these § §  69.511—69.513 reserved December 19, 2008, effective December 20, 2008, 38 Pa.B. 6961. Immediately preceding pages appear at serial pages (255463) to (255464) and (322775).

SMALL DRINKING WATER SYSTEM—STATEMENT
OF POLICY

§ 69.701. Viability of small water systems.

 (a)  General.

   (1)  Many small water systems in this Commonwealth are not viable and need to be restructured. Most new water systems being created in this Commonwealth are small and are likely candidates for becoming nonviable.

   (2)  A viable water system is one which is self-sustaining and has the commitment and financial, managerial and technical capabilities to reliably meet Commission and Department of Environmental Resources (Department) requirements on a long-term basis.

   (3)  It shall be the objective of the Commission and the Department to work closely together and with other agencies and organizations involved in safe drinking water programs to substantially restrict the number of nonviable drinking water systems by discouraging the creation of new nonviable small systems, and at the same time, encourage the restructuring of existing nonviable small systems.

 (b)  Implementation. To accomplish this goal of restricting the number of nonviable drinking water systems, the following efforts will be encouraged and supported:

   (1)  The development and implementation of comprehensive water system facility plans, management plans and financial plans by drinking water systems which enable these systems to operate on a sound business basis to ensure the continuous provision of quality water service that meets the requirements of 66 Pa.C.S. (relating to the Public Utility Code) and the Pennsylvania Safe Drinking Water Act (35 P. S. § §  721.1—721.17).

   (2)  Comprehensive planning at the local, county and regional level to ensure water system viability.

   (3)  The restructuring, physically or administratively, of contiguous and noncontiguous drinking water systems, some of which are nonviable, to form a single viable water system or water authority.

   (4)  The facilitation of the rate process to aid in the provision by PENNVEST, and other affected governmental or other financial bodies, of financial assistance to viable systems and projects which incorporate or encourage accomplishment of paragraphs (1)—(3).

   (5)  The development of safety net programs to deal with nonviable or abandoned water systems.

   (6)  Working with the water industry, government agencies and other affected bodies to educate the public regarding drinking water system regulation, planning and viability issues, and the associated cost and public health benefits derived.

   The provisions of this §  69.701 adopted January 7, 1994, effective January 8, 1994, 24 Pa.B. 158.

SMALL NONVIABLE WATER AND WASTEWATER SYSTEMS—STATEMENT OF POLICY

§ 69.711. Acquisition incentives.

 (a)  General. To accomplish the goal of increasing the number of mergers and acquisitions to foster regionalization, the Commission will consider the acquisition incentives in subsection (b). The following parameters shall first be met in order for Commission consideration of a utility’s proposed acquisition incentive. It should be demonstrated that:

   (1)  The acquisition serves the general public interest.

   (2)  The acquiring utility meets the criteria of viability that will not be impaired by the acquisition; that it maintains the managerial, technical and financial capabilities to safely and adequately operate the acquired system, in compliance with 66 Pa.C.S. (relating to the Public Utility Code), the Pennsylvania Safe Drinking Water Act (35 P. S. § §  721.1—721.17) and other requisite regulatory requirements on a short and long-term basis.

   (3)  The acquired system has less than 3,300 customer connections; the acquired system is not viable; it is in violation of statutory or regulatory standards concerning the safety, adequacy, efficiency or reasonableness of service and facilities; and that it has failed to comply, within a reasonable period of time, with any order of the Department of Environmental Protection or the Commission.

   (4)  The acquired system’s ratepayers should be provided with improved service in the future, with the necessary plant improvements being completed within a reasonable period of time.

   (5)  The purchase price of the acquisition is fair and reasonable and the acquisition has been conducted through arm’s length negotiations.

   (6)  The concept of single tariff pricing should be applied to the rates of the acquired system, to the extent that it is reasonable. Under certain circumstances of extreme differences in rates, or of affordability concerns, consideration should be given to a phase-in of the rate difference over a reasonable period of time.

 (b)  Acquisition incentives. In its efforts to foster acquisition of suitable water and wastewater systems by viable utilities when the acquisitions are in the public interest, the Commission seeks to assist these acquisitions by permitting the use of a number of regulatory incentives. Accordingly, the Commission will consider the following acquisitions incentives:

   (1)  Rate of return premiums. Under 66 Pa.C.S. §  523 (relating to performance factor considerations), additional rate of return basis points may be awarded for certain acquisitions and for certain associated improvement costs, based on sufficient supporting data submitted by the acquiring utility within its rate case filing. The rate of return premium as an acquisition incentive may be the most straightforward and its use is encouraged.

   (2)  Acquisition adjustment. When the acquiring utility’s acquisition cost differs from the depreciated original cost of the water or wastewater facilities first devoted to public use, the difference may be treated as follows for ratemaking purposes:

     (i)   Credit acquisition adjustment. Under 66 Pa.C.S. §  1327(e) (relating to acquisition of water and sewer facilities), when a utility pays less than the depreciated original cost of the acquired system, the acquiring utility may book and include in rate base the depreciated original cost of the acquired system, provided that the difference between the acquisition cost and depreciated original cost should be amortized as an addition to income over a reasonable period of time or be passed through to ratepayers by another methodology that is determined by the Commission. The acquiring utility may argue that no amortization or pass through is appropriate when the acquisition involves a matter of substantial public interest.

     (ii)   Debit acquisition adjustment. Under 66 Pa.C.S. §  1327(a), when a utility pays more than the depreciated original cost of the acquired system, the acquiring utility may book and include in rate base the excess of acquisition cost over depreciated original cost of the acquired system, provided that the utility can meet the requirements of 66 Pa.C.S. §  1327(a). When the acquisition does not qualify under 66 Pa.C.S. §  1327(a), the debit acquisition adjustment should be treated in accordance with generally accepted accounting principles and not be amortized for ratemaking purposes.

   (3)  Deferral of acquisition improvement costs. In cases when the plant improvements are of too great a magnitude to be absorbed by ratepayers at one time, rate recovery of the improvement costs may be recovered in phases. There may be a one time treatment—in the initial rate case-of the improvement costs but a phasing—in of the acquisition, improvements and associated carrying-costs may be allowed over a finite period.

   (4)  Plant improvement surcharge. Collection of a different rate from customers of the acquired system upon completion of the acquisition could be implemented to temporarily offset extraordinary improvement costs. In cases when the improvement benefits only those customers who are newly acquired, the added costs may be allocated on a greater than average level—but less than 100%—to the new customers for a reasonable period of time, as determined by the Commission.

 (c)  Procedural implementation.

   (1)  An acquiring utility that has met the criteria set forth in 66 Pa.C.S. §  1327(a)(1)—(9) for inclusion of a debit acquisition adjustment in its rate base, may elect to have this acquisition adjustment considered on a case-by-case basis as set forth in 66 Pa.C.S. §  1327(b), or as part of its next rate case filing. The acquiring utility should file the supporting documentation outlined in subsection (d) to support the requested acquisition adjustment.

   (2)  The appropriate implementation procedure to qualify for the other acquisition incentives in subsection (b) would be to file the appropriate supporting documentation during the next filed rate case.

   (3)  In acquisition incentive filings, the burden of proof rests with the acquiring utility.

 (d)  Documentation to support inclusion of acquisition adjustment. When an acquiring utility elects to have the acquisition adjustment to its rate base considered as a part of its next rate case filing, the acquiring utility should file the following documentation to support the acquisition adjustment to its rate base:

   (1)  Statement of reliance on existing records. An acquiring utility may elect to rely in whole or in part upon the original cost records of the seller or Commission in determining the original cost of the used and useful assets of the acquired system.

   (2)  Preparation of data to support acquisition adjustment. An acquiring utility, upon its own election, may file an original cost plant-in-service study with the Commission to support its requested acquisition adjustment to its rate base. An original cost study is one method of determining the valuation costs of the property of a public utility. It requires the acquiring utility to develop realistic plant balances and accumulates the records and accounting details that support those balances. Disputes regarding the acquiring utility’s original cost valuation of the assets of the acquired system will be resolved in the context of a rate proceeding when interested parties will have an opportunity to be heard.

     (i)   Contents of an original cost plant-in-service study. When an acquiring utility elects to submit its own original cost of plant-in-service valuation, the acquiring utility is obligated to exercise due diligence and make reasonable attempts to obtain, from the seller, documents related to original cost. In particular, as part of its exercise of due diligence, the acquiring utility should request from the seller, for purposes of determining the original cost plant-in-service valuation, the original cost of the assets being acquired and records relating to contributions in aid of construction (CIAC), such as the following:

       (A)   Accounting records and other relevant documentation and agreements of donations or contributions, services, or property from states, municipalities or other government agencies, individuals, and others for construction purposes.

       (B)   Records of unrefunded balances in customer advances for construction (CAC).

       (C)   Records of customer tap-in fees and hook-up fees.

       (D)   Prior original cost studies.

       (E)   Records of local, State and Federal grants used for construction of utility plant.

       (F)   Relevant PennVEST or Department of Environmental Protection records.

       (G)   Any Commission records.

       (H)   Summary of the depreciation schedules from all filed Federal tax returns.

         (I)   Other accounting records supporting plant-in-service.

     (ii)   Failure of seller to provide cost-related documents. The failure of a seller to provide cost-related documents, after reasonable attempts to obtain the data, will not be a basis for the Commission’s denial of the inclusion of the value of the acquired system’s assets in its proposed rate base. Because the documents obtained from the seller may be incomplete and may result in an inaccurate valuation, the acquiring utility will not be bound by the incomplete documents from the seller in the preparation of its original cost plant-in-service valuation.

     (iii)   Procedure for booking CIAC. The acquiring utility, at a minimum, should book as CIAC contributions that were properly recorded on the books of the system being acquired. If evidence supports other CIAC that was not booked by the seller, the acquiring utility should make a documented effort to determine the actual CIAC and record the contributions for ratemaking purposes, such as lot sale agreements or capitalization vs. expense of plant-in-service on tax returns.

     (iv)   Plant retired/not booked/not used and useful. The acquiring utility should identify all plant retirements and plant no longer used and useful, and complete the appropriate accounting entries.

     (v)   Reconciliation with commission records. In the case of an acquisition of a water or wastewater system that is regulated by the Commission, the acquiring utility should reconcile and explain any discrepancies between the acquiring utility’s original cost plant-in-service valuation and the Commission’s records, to the extent reasonably known and available to the acquiring utility, at the same time the supporting documentation for the study is filed.

 (e)  Time to submit original cost valuation. When the acquiring utility elects to request an acquisition adjustment during its next rate filing, it should submit a copy of its newly prepared original cost plant-in-service valuation of the acquired system or a statement of reliance of the existing records of the Commission or the seller to the Commission’s Secretary’s Bureau, the Bureau of Audits, the Bureau of Fixed Utility Services, the Office of Trial Staff, the Office of Consumer Advocate, and the Office of Small Business Advocate at least 4 months prior to the date that the acquiring utility plans to make its next rate case filing with the Commission.

   (1)  The Commission staff may conduct an audit of the original cost valuation, but if no staff audit is completed and released at public meeting before the date of the rate case filing, the Commission’s determination of the original cost valuation in the rate case will be deemed final action on the original cost valuation and any associated acquisition adjustment, absent subsequently discovered fraud or misrepresentation. When staff completes an audit before the rate case is filed, the results of the audit will not be binding on any party, but rather the audit report will be made available to the public and the report can be presented in the acquiring utility’s next rate case, subject to applicable evidentiary rules.

   (2)  When the acquiring utility makes a rate case filing sooner than the 4-month window, the acquiring utility should not include any revenues or expenses related to the acquisition, including the requested acquisition adjustment in its proposed rate base unless it includes the original cost valuation with the rate filing and one of the following circumstances applies:

     (i)   A compelling reason exists for requesting the acquisition adjustment in the current rate filing.

     (ii)   The acquisition was requested or otherwise directed by the Commission.

     (iii)   No statutory party objects to the inclusion of the acquisition adjustment to the proposed rate base of the acquiring utility.

 (f)  Purchase price of the water and wastewater system. The factors relevant to the reasonableness of the purchase price of the acquired water and wastewater system include:

   (1)  Promotion of long-term viability.

   (2)  Promotion of regionalization.

   (3)  Usage per customer.

   (4)  Growth rates.

   (5)  Cost of improvements.

   (6)  Age of the infrastructure.

   (7)  Return on equity.

   (8)  Existing rates.

   (9)  Purchase price per customer.

   The provisions of this §  69.711 adopted March 29, 1996, effective March 30, 1996, 26 Pa.B. 1380; amended February 13, 1998, effective February 14, 1998, 28 Pa.B. 801; amended September 29, 2006, effective September 30, 2006, 36 Pa.B. 5991; corrected October 6, 2006, effective September 29, 2006, 36 Pa.B. 6107. Immediately preceding text appears at serial pages (255466) to (255468).

   This section cited in 52 Pa. Code §  69.721 (relating to water and wastewater acquisitions).

ACQUISITIONS OF VIABLE WATER AND WASTEWATER SYSTEM—STATEMENT OF POLICY

§ 69.721. Water and wastewater system acquisitions.

 (a)  General. The Commission believes that further consolidation of water and wastewater systems within this Commonwealth may, with appropriate management, result in greater environmental and economic benefits to customers. The regionalization of water and wastewater systems through mergers and acquisitions will allow the water industry to institute better management practices and achieve greater economies of scale. To further this goal, the Commission sets forth the guidance in this section regarding the acquisition of water and wastewater systems. Guidance specifically applicable to the acquisition of nonviable systems is set forth in §  69.711 (relating to acquisition incentives).

 (b)  Inclusion of acquisition assets in rate base. After the approval of an acquisition, as evidenced by the receipt of a certificate of public convenience, an acquiring utility may request the inclusion of the value of the used and useful assets of the acquired system in its rate base. A request will be considered during the acquiring utility’s next filed rate case proceeding. See 66 Pa.C.S. §  1311(a) (relating to valuation of and return on the property of a public utility).

 (c)  Method of valuation of acquisition assets. The assets of the acquired system should be booked at the original cost of the acquired system when first devoted to the public service less the applicable accrued depreciation and related contributions. See 66 Pa.C.S. §  1311(b).

 (d)  Determining original cost of acquisition assets. An acquiring utility may use various methods to support its valuation of the original cost of the used and useful assets of the acquired water or wastewater system. For example, an acquiring utility may elect to rely in whole or in part upon the original cost records of the seller or the Commission in determining the original cost of the used and useful assets of the acquired system that are to be included in its rate base.

 (e)  Preparation of an original cost of plant-in-service valuation. The Commission will not require an acquiring utility to submit a full original cost plant-in-service study in order to determine the value of the assets of the acquired system. An acquiring utility, upon its own election, may file an original cost study with the Commission to support its valuation of the assets of the acquired water and wastewater system proposed to be included in its rate base. A full original cost plant-in-service study is one method of determining the valuation costs of the property of a public utility. It requires the acquiring utility to develop realistic plant balances and accumulates the records and accounting details that support those balances. Disputes regarding the acquiring utility’s original cost valuation of the acquired assets will be resolved in the context of a rate proceeding in which all interested parties will have an opportunity to be heard.

   (1)  Contents of an original cost plant-in-service study. The acquiring utility is obligated to exercise due diligence and make reasonable attempts to obtain, from the seller, documents related to original cost. In particular, as part of its due diligence, the acquiring utility should request from the seller, for purposes of determining the original cost plant-in-service valuation, the original cost of the assets being acquired and records relating to contributions in aid of construction (CIAC), such as the following:

     (i)   Accounting records and other related documentation and agreements of donations or contributions, services, or property from states, municipalities or other government agencies, individuals, and others for construction purposes.

     (ii)   Records of unrefunded balances in customer advances for construction (CAC).

     (iii)   Records of customer tap-in fees and hook-up fees.

     (iv)   Prior original cost studies.

     (v)   Records of local, State and Federal grants used for construction of utility plant.

     (vi)   Relevant PennVEST or Department of Environmental Protection records.

     (vii)   Any Commission records.

     (viii)   Summary of the depreciation schedules from all filed Federal tax returns.

     (ix)   Other accounting records supporting plant-in-service.

   (2)  Failure of seller to provide cost-related documents. The failure of a seller to provide cost-related documents, after reasonable attempts to obtain the data, will not be a basis for the Commission’s denial of the inclusion of the value of the acquired system’s assets in its proposed rate base. Because the documents obtained from the seller may be incomplete and may result in an inaccurate valuation, the acquiring utility will not be bound by the incomplete documents from the seller in the preparation of its original cost plant-in-service valuation.

   (3)  Procedure for booking CIAC. The acquiring utility, at a minimum, should book as CIAC contributions that were properly recorded on the books of the system being acquired. If evidence supports other CIAC that was not booked by the seller, the acquiring utility should make a documented effort to determine the actual CIAC and record the contributions for ratemaking purposes, such as lot sale agreements or capitalization versus expenses of plant-in-service on tax returns.

   (4)  Plant retired/not booked/not used and useful. The acquiring utility should identify all plant retirements and plant no longer used and useful and complete the appropriate accounting entries.

   (5)  Reconciliation with commission records. In the case of an acquisition of a water or wastewater system that is regulated by the Commission, the acquiring utility should reconcile and explain any discrepancies between the acquiring utility’s original cost plant-in-service valuation and the Commission’s records, to the extent reasonably known and available to the acquiring utility, at the same time the supporting documentation for the study is filed.

 (f)  Time to submit original cost valuation. When the acquiring utility elects to request inclusion of its acquisition in its rate base, it should submit a copy of its newly prepared original cost plant-in-service valuation of the acquired system or a statement of reliance of the existing records of the Commission or the seller to the Commission’s Secretary’s Bureau, the Bureau of Audits, the Bureau of Fixed Utility Services, the Office of Trial Staff, the Office of Consumer Advocate and the Office of Small Business Advocate at least 4 months prior to the date that the acquiring utility plans to make its next rate case filing with the Commission.

   (1)  The Commission staff may conduct an audit of the original cost valuation, but if no staff audit is completed and released at public meeting before the date of the rate case filing, the Commission’s determination of the original cost valuation in the rate case will be deemed final action on the original cost valuation, absent subsequently discovered fraud or misrepresentation. When staff completes an audit before the rate case is filed, the results of the audit will not be binding on any party, but rather the audit report will be made available to the public and the report can be presented in the acquiring utility’s next rate case, subject to applicable evidentiary rules.

   (2)  When the acquiring utility makes a rate case filing sooner than the 4-month window, the acquiring utility should not include any revenues or expenses related to the acquisition, including the requested acquisition adjustment in its proposed rate base unless it includes the original cost valuation with the rate filing and one of the following circumstances applies:

     (i)   A compelling reason exists for requesting the acquisition in the current rate filing.

     (ii)   The acquisition was requested or otherwise directed by the Commission.

     (iii)   No statutory party objects to the inclusion of the acquisition to the proposed rate base of the acquiring utility.

 (g)  Acquisition incentives. In its efforts to foster the acquisitions of smaller, less viable water and wastewater systems by larger more viable systems, the Commission, under 66 Pa.C.S. §  523 (relating to performance factor consideration), has broad latitude to allow the acquiring utility to request a rate of return premium in a subsequent rate case. The allowance of a rate of return premium, as an acquisition incentive for an acquisition that falls outside of the parameters of 66 Pa.C.S. §  1327 (relating to acquisition of water and sewer utilities), may be requested by those utilities that have a demonstrated track record of acquiring and improving the service provided to the customers of smaller and less viable water systems. The allowance of additional rate of return basis points may be awarded based on sufficient supporting data submitted by the utility within its rate case filing.

   The provisions of this §  69.721 adopted September 29, 2006, effective September 30, 2006, 36 Pa.B. 5991.

DIVERSITY AT MAJOR JURISDICTIONAL UTILITY
COMPANIES—STATEMENT OF POLICY

§ 69.801. General.

 From a business perspective, diversity should be associated with a company’s business objectives and strategies. The Commission strongly believes that diversity is an economic reality that corporate entities must include in their corporate strategies now and in the future. The Commission intends to take the next step by encouraging major jurisdictional utility companies operating in this Commonwealth to incorporate diversity in their business strategy in connection with the procurement of goods and services.

   The provisions of this §  69.801 adopted March 24, 1995, effective March 25, 1995, 25 Pa.B. 1084.

 The following words and terms, when used in § §  69.801 and 69.803—69.809, have the following meanings, unless the context clearly indicates otherwise:

   African-Americans—United States citizens or legal aliens with permanent residence status in the United States who have origins in any racial groups of Africa.

   Asian Pacific-Americans—United States citizens or legal aliens with permanent residence status in the United States who have origins in Asia, includingpersons from Japan, China, the Philippines, Vietnam, Korea, Samoa, Guam, the United States Trust Territory of the Pacific Islands (Republic of Palau), the Northern Mariana Islands, Laos, Kampuchea (Cambodia), Taiwan, Burma, Thailand, Malaysia, Indonesia, Singapore, Brunei, Republic of the Marshall Islands and the Federated States of Micronesia.

   Control—The exercise of the power to make policy decisions.

   Diversity—The attainment of organizational objectives by maximizing the contributions of individuals from every segment of the population.

   Exempt procurement—A product or service which may be removed from the dollar base used to establish minimum improvement levels, because of the demonstrated unavailability of a minority/women/people with disabilities-owned business currently capable of supplying a product or service. The term may also include one or more of the following situations:

     (i) The vendor is the original equipment manufacturer.

     (ii) The vendor is the only known source of the product or service.

     (iii) A plant emergency situation dictates use of a specific vendor.

     (iv) Purchases from affiliates, corporate parents and their subsidiaries.

   Hispanic-Americans—United States citizens or legal aliens with permanent residence status in the United States who have origins in Mexico, Puerto Rico, Cuba, South America, Central America and the Caribbean.

   Long-term plan—A plan applicable to a period of 5 years.

   MBE—Minority-Owned Business Enterprise—A business enterprise that is at least 51% owned by a minority individual or group or individuals; or a publicly-owned business that has at least 51% of its stock owned by one or more minority individuals, and whose management and daily business operations are controlled by these individuals. ‘‘Minority’’ may include African-Americans, Hispanic-Americans, Native Americans and Asian Americans, as well as other groups found to be disadvantaged under section 8(a) of the Small Business Act (15 U.S.C.A. §  637(d)).

   MIL—Minimum Improvement Level—A level or goal which, when achieved, indicates progress in a preferred direction. An MIL is neither a requirement nor a quota, and no specific participation levels are intended.

   Major jurisdictional utility company—Electric, gas, water and telephone utilities whose net plant in service is valued at $10 million or more. The term includes major telephone companies, defined as companies exceeding 50,000 access lines.

   Midterm plan—A plan applicable to a period of 3 years.

   Native-Americans—United States citizens or legal aliens with permanent residence status in the United States who have origins in any of the original peoples of North America or Hawaiian Islands, in particular, American Indians, Eskimos, Aleutes and Native Hawaiians.

   Operate—Active involvement in the day-to-day management. The term involves more than acting as officers or directors.

   Short-term plan—A plan applicable to a period of 1 year.

   Subcontinent Asian-Americans—United States citizens or legal aliens with permanent residence status in the United States who have origins in India, Pakistan, Bangladesh, Sri Lanka, Bhutan or Nepal.

   Subcontract—An agreement or arrangement between a contractor and a party or person—in which the parties do not stand in the relationship of an employer and an employe—for the furnishing of supplies or services for the use of real or personal property, including lease arrangements, which in whole or in part, is necessary to the performance of any one or more contracts.

   Substantial objectives—Objectives which are realistic and clearly demonstrate a utility’s commitment to increase minority/women/persons with disabilities-owned business share of the utility’s purchases and contracts.

   WBE—Women-Owned Business Enterprise—A business enterprise that is at least 51% owned by a woman or women who are United States citizens or legal aliens with permanent residence status in the United States; or a publicly-owned business that has at least 51% of its stock owned by one or more women, and whose management and daily business operations are controlled by one or more women who are United States citizens or legal aliens with permanent residence status in the United States.

   W/MBE—A WBE or an MBE.

   The provisions of this §  69.802 adopted March 24, 1995, effective March 25, 1995, 25 Pa.B. 1084.

 The Commission encourages major jurisdictional utility companies to implement diversity programs. This effort may include the following:

   (1)  The articulation of a corporate policy by the senior executives of the major jurisdictional utility company committing the utility to improving its level of diversity in the workplace and within its procurement process.

   (2)  The development and implementation of a corporate-wide diversity program with specified goals and objectives for each year.

   (3)  The appointment of utility managers to be responsible for the success of the program.

   (4)  The training of managers regarding implementing diversity initiatives in the areas of employment and contracting for goods and services.

   (5)  The location of qualified minority/women/ persons with disabilities-owned business contractors and mentoring, partnering and training qualified women/minority/persons with disabilities-owned businesses contractors to serve the needs of the major jurisdiction utility company.

   The provisions of this §  69.803 adopted March 24, 1995, effective March 25, 1995, 25 Pa.B. 1084.

 The Commission recommends that major jurisdictional utility companies strive to take maximum efforts to provide that minority/women/ persons with disabilities-owned businesses have an equal opportunity to compete for the purchase of equipment, supplies, services, fuels, materials, construction, professional services advertising and the like. The Commission encourages major jurisdictional utility companies to develop a diversity program which is designed to provide that a fair proportion of products and services contracts are offered to minority/women/persons with disabilities-owned businesses. It is recommended that the major jurisdictional utility companies adopt the general guidelines in § §  69.805—69.808 in the development or enhancement of their diversity program relative to contracting for goods and services.

   The provisions of this §  69.804 adopted March 24, 1995, effective March 25, 1995, 25 Pa.B. 1084.

 The major jurisdictional utility companies are encouraged to have an appropriate executive accountable for providing overall direction and guidance to the minority/women/persons with disabilities-owned business program. Each major jurisdictional utility company is invited to maintain a staff to implement program requirements concerning the women/minority/ persons with disabilities-owned businesses. It may not be necessary for the major jurisdictional utility company to increase its staff or to reassign existing staff to minority/ women/persons with disabilities-owned business program responsibilities if the major jurisdictional utility company can implement its program effectively through its current resource commitment and management structure.

   The provisions of this §  69.805 adopted March 24, 1995, effective March 25, 1995, 25 Pa.B. 1084.

 By March 1 of each year, each major jurisdictional utility company is encouraged to annually set substantial and verifiable short-term, midterm and long-term plans for the utilization of minority/women/persons with disabilities-owned businesses. Minimum improvement levels should be set annually for each major product and services category which provides opportunities for procurement.

   (1)  The major jurisdictional utility companies may consider the following factors in setting their minimum improvement levels:

     (i)   The total utility purchasing or contracting projections, or both, including fees to financial (for example, financial institutions and the like), advertising, legal and professional services.

     (ii)   Availability of minority/women/persons with disabilities-owned businesses in the major jurisdictional utility company’s service area and surrounding communities.

     (iii)   Market dynamics based on historical data and trends.

     (iv)   Other appropriate factors which would increase the minority/ women/persons with disabilities-owned businesses share of utility business.

   (2)  Program objectives should be established for both minority-owned, non-minority women-owned and persons with disabilities-owned business enterprises.

   (3)  A major jurisdictional utility company may exclude a specific product or service when it is clearly evident the minority/women/ persons with disabilities-owned businesses do not provide a specific product or service, or that exempt procurement is the only available procurement method for obtaining that specific product or service. Each utility should demonstrate the unavailability of minority/women/ persons with disabilities-owned businesses capable of supplying these products and services on a case by case basis. Because there may in the future be minority/women/persons with disabilities-owned businesses capable of supplying products or services currently being supplied by an exempt procurement provider, the major jurisdictional utility company should explain in its annual report the continued use of any exempt procurement provider.

   (4)  A major jurisdictional utility company which is presently purchasing products or services from affiliates may subtract the dollars paid to affiliates for these products or services from the total dollars used as the basis for establishing minimum improvement levels for purchases from minority/women/persons with disabilities-owned businesses if the major jurisdiction utility company requires the affiliate to establish an appropriate subcontracting program for minority/women/persons with disabilities-owned businesses where the affiliates employ subcontractors. A major jurisdictional utility company which takes advantage of this section should report to the Commission, in its annual report, whether the affiliates have established a subcontracting program and describe the results of the program.

   (5)  Overall program levels should be expressed as a percentage of total dollars awarded to outside suppliers and contractors other than products and services which fall within an exempt procurement category established by the major jurisdictional utility company.

   (6)  Payments for fuel, purchased power and franchise tax fees need not be included in the procurement dollar base used to establish minimum improvement levels.

   (7)  Each major jurisdictional utility company is encouraged to make special efforts to increase utilization of minority/women/persons with disabilities-owned businesses, in conjunction with its established minimum improvement levels, in areas that are considered to be technical in nature, and where there has been low utilization, such as consultants, legal and financial services.

   (8)  Each major jurisdictional utility company is invited to consider the utilization of minority/women/persons with disabilities-owned businesses when outsourcing noncore business functions and report these contracts as part of the annual report.

   The provisions of this §  69.806 adopted March 24, 1995, effective March 25, 1995, 25 Pa.B. 1084.

 Each major jurisdictional utility company is encouraged to establish and maintain a subcontracting program for its prime contractors to utilize minority/women/persons with disabilities-owned business subcontractors. The subcontracting program will serve as an enhancement to and not a replacement for the utility’s minority/women/persons with disabilities-owned business program.

   (1)  The major jurisdictional utility company should incorporate in purchase orders, requests for bid proposals and other appropriate procurement documents related to procurement efforts subject to its subcontracting program, a statement such as follows:

  ‘‘It is the policy of this utility that businesses owned by minorities, women and persons with disabilities should have an equal opportunity to compete for subcontracts. The contractor agrees to use its best efforts to carry out this policy to the fullest extent consistent with the efficient performance of this contract.’’

   (2) The major jurisdictional utility company is encouraged to assist its prime contractors in developing plans to increase the opportunities for participation by minority/women/persons with disabilities-owned business subcontractors. Prime contractors will be encouraged to submit these plans and the results to the utility.

   (3)  The subcontracting program should apply to purchases/contracts exceeding $500,000 for products and services, and for construction contracts over $1 million. The subcontracting program need not be applied to the procurement of products and services in excluded categories.

   (4)  Each major jurisdictional utility company is encouraged to inform suppliers of products and services that subcontracting with businesses owned by minority/women/persons with disabilities is a factor that may be considered in the bid evaluation process.

   (5)  Each major jurisdictional utility company should include awards to verified minority/women/persons with disabilities-owned business subcontractors in each report to the Commission.

   The provisions of this §  69.807 adopted March 24, 1995, effective March 25, 1995, 25 Pa.B. 1084.

 Each major jurisdictional utility company should implement an outreach program to inform, to recruit and to expand procurement activities to qualified and qualifiable businesses owned by minority/women/persons with disabilities. Outreach activities may vary for each utility depending on its size, service territory and specific lines of business. Each major jurisdictional utility company should, at a minimum, consider implementation of the following:

   (1)  Actively seek out opportunities to identify business contractors and suppliers that are owned by minority/women/persons with disabilities and to expand source pools.

   (2)  Actively support the efforts of organizations experienced in promoting the interest of minority/women/persons with disabilities-owned businesses.

   (3)  Initiate business development partnerships (long-term), joint ventures or venture capital projects with minority/women/persons with disabilities-owned businesses such as outsourcing agreements of noncore utility business functions when applicable to allow business expansion within the minority/women/persons with disabilities-owned business community. Provide technical/management support (short-term) to ensure the success of this initiative.

   (4)  Work with minority/women/persons with disabilities-owned business contractors to facilitate contracting relationships by explaining utility qualification requirements, bidding and contracting procedures, materials requirements, invoicing and payment schedules and other procurement practices and procedures.

   The provisions of this §  69.808 adopted March 24, 1995, effective March 25, 1995, 25 Pa.B. 1084.

 (a)  The major jurisdictional utility companies are encouraged to file with the Secretary of the Commission and the Bureau of Public Liaison by March 1 of each year, beginning in 1995, an annual report describing their diversity program activity for the prior year. The annual report should contain at least the following elements:

   (1)  A description of minority/women/persons with disabilities-owned business program activities engaged in during the previous calendar year. This description includes both internal and external activities.

   (2)  A description of progress in meeting or exceeding the proposed levels and an explanation of circumstances that may have caused the utility to fall short of its established minimum improvement levels.

   (3)  A description of innovative approaches to encourage minority/ women/persons with disabilities-owned business development, partnering, subcontracting, joint-venturing and venture capital projects.

   (4)  A summary of prime contractors which report utilization of minority/women/persons with disabilities-owned business subcontractors indicating the number of disability-owned business subcontractors and the associated dollars.

   (5)  An explanation for the continued classification of exempt procurement for products or services which have been used to set minimum levels of improvement because of the established unavailability of minority/women/persons with disabilities-owned business suppliers.

   (6)  Sections 69.801—69.808 and this section permit utilities to break specific categories down further than presently suggested—for example, reporting contracts awarded to Filipino Americans separately from those awarded to Asian Pacific-Americans, or reporting male and female results within minority-owned classifications. Data reported for nonminority women, may be reported separately from data reported for minority business enterprises.

 (c)  Information that is otherwise unobtainable to the major jurisdictional utility company, for example, prime contractor utilization of minority/women/persons with disabilities-owned businesses as subcontractors, should be reported in the annual filings.

   The provisions of this §  69.809 adopted March 24, 1995, effective March 25, 1995, 25 Pa.B. 1084.

   This section cited in 52 Pa. Code §  69.802 (relating to definitions).

UTILITY STOCK TRANSFER UNDER 66 PA.C.S. §  1102(a)(3)—STATEMENT OF POLICY

§ 69.901. Utility stock transfer under 66 Pa.C.S. §  1102(a)(3).

 (a)  Background.

   (1)  Commission jurisdiction over the acquisition or transfer of public utility property is governed by 66 Pa.C.S. §  1102(a)(3) (relating to enumeration of acts requiring certificate). The ambiguous language in 66 Pa.C.S. §  1102(a)(3) has historically caused considerable uncertainty among the Commission, its staff and the industry regarding what type of transaction requires Commission approval. This uncertainty has been particularly apparent regarding stock transfers which may equate to the transfer of utility property.

   (2)  Recently, the Commission has examined 66 Pa.C.S. §  1102(a)(3) and determined that the transfer of stock or other voting interest of a utility’s parent is jurisdictional regardless of the remoteness of the transaction if the effect of the transaction is to change the control of a utility. Joint Application of Commonwealth Telephone Company, et al., A-310800,F.0006, (October 22, 1993). Furthermore, the Commission has held that a transaction resulting in a change of the de facto controlling interest in a utility or its parent, regardless of the tier in the corporate organization, constitutes a change of control of the utility and is jurisdictional under 66 Pa.C.S. §  1102(a)(3). Joint Application of Paging Network of Pittsburgh, Inc. et al., A-330013,F.0005. In view of these Commission holdings, it is necessary to further define and establish clear standards regarding what transfer of voting interest constitutes a change in de facto control and thereby constitutes the transfer or acquisition of utility property within the intendment of 66 Pa.C.S. §  1102(a)(3).

 (b)  Policy.

   (1)  A transaction or series of transactions resulting in a new controlling interest is jurisdictional when the transaction or transactions result in a different entity becoming the beneficial holder of the largest voting interest in the utility or parent, regardless of the tier. A transaction or series of transactions resulting in the elimination of a controlling interest is jurisdictional when the transaction or transactions result in the dissipation of the largest voting interest in the utility or parent, regardless of the tier.

   (2)  For purposes of this section, a controlling interest is an interest, held by a person or a group acting in concert, which enables the beneficial holders to control at least 20% of the voting interest in the utility or its parent, regardless of the remoteness of the transaction. In determining whether a controlling interest is present, voting power arising from a contingent right shall be disregarded.

   (3)  Under this section, intrafamily transactions made with only nominal consideration do not constitute a change in de facto control of a utility. For purposes of this section, an intrafamily transaction is a transfer or acquisition of stock to or from a spouse, parent, sibling or direct descendent or to or from a trust which has permissible income or remainder beneficiaries which include the stockholder or the stockholder’s spouse, parent, sibling or direct descendent or to an estate pending distribution or to a guardian or attorney-in-fact acting on behalf of a stockholder.

   The provisions of this §  69.901 adopted October 21, 1994, effective October 22, 1994, 24 Pa.B. 5328.

   This section cited in 52 Pa. Code §  63.324 (relating to commission approval of a general rule transaction subject to 66 Pa.C.S. § §  1102(a)(3) and 1103); and 52 Pa. Code §  63.325 (relating to commission approval of a pro forma transaction subject to 66 Pa.C.S. § §  1102(a)(3) and 1103).

LOCAL LAND-USE PLANS AND ORDINANCES

§ 69.1101. Local land-use plans and ordinances in issuing certificates of public convenience.

 To further the State’s goal of making State agency actions consistent with sound land-use planning, and under the act of June 22, 2000 (P. L. 483, No. 67) and the act of June 23, 2000 (P. L. 495, No. 68), the Commission will consider the impact of its decisions upon local comprehensive plans and zoning ordinances. This will include reviewing applications for:

   (1)  Certificates of public convenience.

   (2)  Siting electric transmission lines.

   (3)  Siting a public utility ‘‘building’’ under section 619 of the Municipalities Planning Code (53 P. S. §  10619).

   (4)  Other Commission decisions.

   The provisions of this §  69.1101 adopted February 16, 2001, effective February 17, 2001, 31 Pa.B. 951.

FACTORS AND STANDARDS FOR EVALUATING LITIGATED AND SETTLED PROCEEDINGS

§ 69.1201. Factors and standards for evaluating litigated and settled proceedings involving violations of the Public Utility Code and Commission regulations—statement of policy.

 (a)  The Commission will consider specific factors and standards in evaluating litigated and settled cases involving violations of 66 Pa.C.S. (relating to Public Utility Code) and this title. These factors and standards will be utilized by the Commission in determining if a fine for violating a Commission order, regulation or statute is appropriate, as well as if a proposed settlement for a violation is reasonable and approval of the settlement agreement is in the public interest.

 (b)  Many of the same factors and standards may be considered in the evaluation of both litigated and settled cases. When applied in settled cases, these factors and standards will not be applied in as strict a fashion as in a litigated proceeding. The parties in settled cases will be afforded flexibility in reaching amicable resolutions to complaints and other matters so long as the settlement is in the public interest. The parties to a settlement should include in the settlement agreement a statement in support of settlement explaining how and why the settlement is in the public interest. The statement may be filed jointly by the parties or separately by each individual party.

 (c)  The factors and standards that will be considered by the Commission include the following:

   (1)  Whether the conduct at issue was of a serious nature. When conduct of a serious nature is involved, such as willful fraud or misrepresentation, the conduct may warrant a higher penalty. When the conduct is less egregious, such as administrative filing or technical errors, it may warrant a lower penalty.

   (2)  Whether the resulting consequences of the conduct at issue were of a serious nature. When consequences of a serious nature are involved, such as personal injury or property damage, the consequences may warrant a higher penalty.

   (3)  Whether the conduct at issue was deemed intentional or negligent. This factor may only be considered in evaluating litigated cases. When conduct has been deemed intentional, the conduct may result in a higher penalty.

   (4)  Whether the regulated entity made efforts to modify internal practices and procedures to address the conduct at issue and prevent similar conduct in the future. These modifications may include activities such as training and improving company techniques and supervision. The amount of time it took the utility to correct the conduct once it was discovered and the involvement of top-level management in correcting the conduct may be considered.

   (5)  The number of customers affected and the duration of the violation.

   (6)  The compliance history of the regulated entity which committed the violation. An isolated incident from an otherwise compliant utility may result in a lower penalty, whereas frequent, recurrent violations by a utility may result in a higher penalty.

   (7)  Whether the regulated entity cooperated with the Commission’s investigation. Facts establishing bad faith, active concealment of violations, or attempts to interfere with Commission investigations may result in a higher penalty.

   (8)  The amount of the civil penalty or fine necessary to deter future violations. The size of the utility may be considered to determine an appropriate penalty amount.

   (9)  Past Commission decisions in similar situations.

   (10)  Other relevant factors.

   The provisions of this §  69.1201 adopted December 21, 2007, effective December 22, 2007, 37 Pa.B. 6755.

GUIDELINES FOR DETERMINING PUBLIC UTILITY STATUS

§ 69.1401. Guidelines for determining public utility status—statement of policy.

 (a)  Coverage. This section applies to all utility projects or services, including alternative energy systems.

 (b)  Purpose. This section provides guidance to developers of all utility projects or services, including developers of alternative energy systems under the Alternative Energy Portfolio Standards Act (73 P. S. § §  1648.1—1648.8), in facilitating the design of projects and business plans.

 (c)  Fact based determination. The Commission will consider the status of a utility project or service based on the specific facts of the project or service and will take into consideration the following criteria in formulating its decision:

   (1)  The service being provided by the utility project is merely incidental to nonutility business with the customers which creates a nexus between the provider and customer.

   (2)  The facility is designed and constructed only to serve a specific group of individuals or entities, and others cannot feasibly be served without a significant revision to the project.

   (3)  The service is provided to a single customer or to a defined, privileged and limited group when the provider reserves its right to select its customers by contractual arrangement so that no one among the public, outside of the selected group, is privileged to demand service, and resale of the service is prohibited, except to the extent that a building or facility owner/operator that manages the internal distribution system serving the building or facility supplies electric power and related electric power services to occupants of the building or facility. See 66 Pa.C.S. § §  102 and 2803 (relating to definitions).

 (d)  Contractual language permitting modifications. The Commission will not deem a utility project or service that satisfies the criteria under subsection (c) to be a public utility based solely on the fact that the relevant contractual provisions between the utility service provider or project developer and end-user customers permit:

   (1)  The utility service provider or project developer to substitute customers or to rearrange the project.

   (2)  The service provider or utility project developer to revise the customer group as a result of a material change in circumstances, including an instance when the actual output from the project proves to be materially less than or greater than projected levels.

 (e)  Modification of project or service. Implementation of contractual provisions that result in an actual increase in the original customer number, an actual alteration to the nature of the relationship between the project developer and the original customer group, an alteration to the select nature of the original customer group or other material change in regard to the original customer group may result in a change to the nonpublic utility status of the utility project or service.

 (f)  Chief Counsel opinion letter. A project developer may request informal advice from the Chief Counsel regarding the jurisdictional status of a utility project or service. The opinion of counsel letter will be issued under §  1.96 (relating to unofficial statements and opinions by Commission personnel).

   (1)  A request for opinion of counsel letter must be directed to the Commission’s Chief Counsel and contain the facts necessary to render an opinion as to the jurisdictional status of the utility project or service. The opinion will be based solely on the facts provided and limited to the facts stated in the request.

   (2)  The Chief Counsel will file a copy of the opinion of counsel letter with the Commission’s Secretary. The copy of the opinion of counsel letter will be filed at Docket No. M-00051865 F.0002 and will constitute constructive notice of the utility project or service that is the subject of the opinion. The Commission will publish public notice of the issuance of the letter in the Pennsylvania Bulletin. Opinion of counsel letters filed at the previous docket number will be available for public access upon request.

   (3)  The act of requesting an opinion of counsel letter may be considered as evidence of a good faith effort to operate in accordance with the law by the project developer of a utility project or service and may be considered as a mitigating factor in imposition of fines and penalties in future complaint proceedings alleging de facto public utility operations.

   (4)  A change in the nature or scope of the operation of the utility project or service may result in a change in the informal advice rendered by an opinion of counsel letter. When a change occurs in the facts stated in the request, a project developer may not rely on the existing Chief Counsel opinion letter but the project developer may request a supplemental Chief Counsel opinion letter.

 (g)  Notice and disclosure statement. A utility service provider or project developer may voluntarily file with the Commission’s Secretary a notice and disclosure statement describing the nature and scope of the operation of a utility project or service with an assertion of its nonpublic utility status.

   (1)  Information that will allow for a determination to be made as to the jurisdictional status of the utility project or service, including its location, capacity output and the projected number of customers served, should be provided in the notice and disclosure statement. The reasons that the utility project or service does not constitute a public utility facility or provide public utility service should be explained with reference to the criteria presented in this section.

   (2)  The notice and disclosure statement will be filed at Docket No. M-00051865 F.0002 and will be available for public access upon request. The Commission will publish public notice of the filing in the Pennsylvania Bulletin. The filed notice and disclosure statement will constitute constructive notice of the asserted nonpublic utility status of the utility project or service.

   (3)  The act of voluntarily filing a notice and disclosure of nonpublic utility status may be considered as evidence of a good faith effort to operate in accordance with the law by the project developer of a utility service or utility service provider and may be considered as a mitigating factor in imposition of fines and penalties in future complaint proceedings alleging de facto public utility operations.

   (4)  A notice and disclosure statement of nonpublic utility status may be amended to report a change in the nature or operation of the utility project or service that may affect its jurisdictional status. An amended notice and disclosure statement should be filed with the Commission’s secretary as soon as practicable after a change takes place.

   The provisions of this §  69.1401 adopted January 5, 2007, effective January 6, 2007, 37 Pa.B. 29.

UNSCHEDULED WATER SERVICE INTERRUPTIONS AND ASSOCIATED ACTIONS

§ 69.1601. General.

 (a)  The purpose of this statement of policy is to provide guidance to the water industry relating to unscheduled water service interruptions, particularly regarding the types of public notice and associated actions that will be deemed acceptable and appropriate for meeting the safe, reasonable and adequate standard in 66 Pa.C.S. §  1501 (relating to character of service and facilities) and for complying with the Commission’s regulation in §  56.71 (relating to interruption of service). It is imperative that affected ratepayers/occupants receive actual, timely and sufficient notice of unscheduled service interruptions whenever a situation affects water quality or quantity and particularly when the water is unsafe to drink.

 (b)  Affected ratepayers/occupants should be notified when 2,500 or 5%, whichever is less, of a utility’s total ratepayers/occupants have an unscheduled service interruption involving any reduction in the quantity of water in a single incident of 6 or more consecutive hours. Timely notification of fewer customers, however, is recommended when practicable. When there is an unscheduled service interruption involving the quality of water, water utilities should follow the applicable Department of Environmental Protection regulations regarding the public notification requirements for events requiring Tier 1 notification under 25 Pa. Code §  109.408(b) (relating to Tier 1 public notice—form, manner and frequency of notice), or Tier 2 notification under 25 Pa. Code §  109.409(b). Timely notification of customers in other incidents affecting the quantity or quality of water, such as water in short supply, discolored or sediment-laden, however, is recommended when practicable. It is also recommended that utilities set as a goal the Tier 1 time frame of ‘‘as soon as possible’’ rather than ‘‘no later than 24 hours’’ and the Tier 2 time frame of ‘‘as soon as possible’’ rather than ‘‘but no later than 30 days.’’

 (c)  This statement of policy should not be considered to modify or replace in any way the public notice requirements of the Department of Environmental Protection found in 25 Pa. Code § §  109.407—109.416 (relating to public notification).

 (a)  Acceptable methods of public notification. In the event of an unscheduled water service interruption, the following acceptable methods of public notification should be considered and utilized as appropriate:

   (1)  Mass media. Facsimile/electronic mail notification to local radio and television stations, cable systems, newspapers and other print and news media as soon as possible after the event occurs. These notifications must provide relevant information about the event, such as the affected locations, its potential impact including the possible duration of the outage, the possible adverse health effects and the population or subpopulation particularly at risk, and a description of actions affected ratepayers/occupants should take to ensure their safety, with updates as often as needed. Updates should be provided on a predictable, regular schedule for the duration of the event. The Commission’s Office of Communications and Emergency Preparedness Coordinator should also receive these notifications.

   (2)  Web site. Use of the utility’s own Internet web site and 24/7 emergency phone line and integrated voice response system to provide relevant information about the event, such as the affected locations, estimated duration, its potential impact including possible adverse health effects and the population or subpopulation particularly at risk, and a description of actions affected ratepayers/occupants should take to ensure their safety, with updates as often as needed. A section of the utility’s web site shall be dedicated to presenting outage information where regular updates of the number of customers without service by geographic area and estimated restoration times are available. Depending on the utility’s system limitations, this could be as simple as a PDF or spreadsheet file of information that is updated at regular intervals.

   (3)  Automated dialer system. Automated dialer system (outbound dialing) notification to affected ratepayers’/occupants’ landline or wireless phones. Updates should be provided at regular intervals or if the estimated restoration time changes by more than 2 hours.

   (4)  Actual notice. Actual notice to affected health care and child care facilities and other facilities, for example, schools and restaurants, as determined by consultation with the Department of Environmental Protection, the Department of Agriculture, the Department of Health, the Department of Aging and other State agencies as necessary.

   (5)  Miscellaneous. Other types of direct or actual notice, such as doorknob flyers distributed to affected ratepayers/occupants, when feasible.

   (6)  Electronic mail and other emerging technology. Electronic mail and text message notification to affected customers who have opted to receive notice through use of these methods. The use of emerging technology such as social media is strongly encouraged.

   (7)  Emergency alert system. Coordination with State and local emergency management agencies as needed to use the emergency alert system for qualifying situations.

 (b)  NIMS standards. Utilities should strive to follow the National Incident Management System (NIMS) and its Public Information System to organize all information throughout the utility into one unified message.

   (1)  Crisis communication plans. Utility crisis communication plans should be in writing and every attempt should be made to be consistent with Nationally-approved NIMS standards.

   (2)  Coordination. If more than one utility is affected in the same geographic region, strong consideration should be given to implementing the NIMS based Joint Information System/Joint Information Center, including coordinating messages on safety and other consumer information tips during outages. This would allow for coordination and integration of information across jurisdictions, especially on universal messages such as actions residents should take to ensure safety.

   (3)  Public notice templates. Utilities should have public notice templates prepared in advance to be available when needed to avoid wasting critical time developing materials when confronted with an unscheduled service interruption or emergency situation. The notices should cover all possible scenarios from water conservation to boil water alerts to contaminants of concern and associated health effects, safety and shelter information, estimated restoration times and times when updated information will be provided. Smaller utilities can refer to resources that are available on the web sites of the Department of Environmental Protection, the United States Environmental Protection Agency, the Pennsylvania Section of the American Water Works Association and the Pennsylvania Chapter of the National Association of Water Companies for assistance in developing public notice templates.

 (c)  Contact information. To ensure that the public is informed, utilities should have a knowledgeable contact person stationed onsite during the emergency, if possible, to communicate to the public and media on behalf of the company. Regular media updates should be scheduled at predictable times.

   (1)  Spokesperson. A single point of contact should be established as the sole media spokesperson for the utility for that time period. During extended outages, a secondary media spokesperson could be utilized as the sole contact for a specific period of time.

   (2)  Talking points and informational sheets. Talking points or informational sheets should be provided to customer service representatives and others who may come in contact with the public during the course of the outage to strive toward consistency of message. This information should also be shared with the Commission’s Office of Communications, its Emergency Preparedness Coordinator and county emergency management agencies. For employees that may have contact with the public but will not be able to receive up-to-date outage information in the course of their duties, the utility should instruct those employees to direct the public to appropriate information sources.

 (a)  Water utilities need to make reasonable efforts to ensure that adequate quantities of alternative supplies of water essential for domestic use are made available in a sufficient number of conspicuous and predetermined locations relative to the number of ratepayers/occupants affected by the incident. This includes the use of water tankers or free bottled water, or both. Utilities should ensure that ratepayers/occupants are adequately notified of the times available and locations of alternative water supplies. When bottled water is used, utilities should have plans in place, based on prior coordination with local vendors, to have adequate supplies to last for the duration of the outage. The Commission encourages utilities to work proactively with community-based organizations that would have readily available information on the location and special needs of affected elderly or homebound ratepayers/occupants in the area.

 (b)  Notice should be made to Commission personnel as soon as possible upon a utility becoming aware of an unscheduled service interruption. It should be noted that §  67.1(c) (relating to general provisions) already directs utilities to contact the Commission within 1 hour following preliminary assessment of conditions. Furthermore, jurisdictional utilities should maintain lists of appropriate Commission contact personnel, including current after-hour contact numbers.

   The provisions of this §  69.1603 adopted December 15, 2006, effective December 16, 2006, 36 Pa.B. 7624.

UTILITY SERVICE OUTAGE PUBLIC NOTIFICATION GUIDELINES—NATURAL GAS DISTRIBUTION MARKET

§ 69.1701. Scope.

 This section and §  69.1702 (relating to notification guidelines) provide guidelines to the natural gas distribution market regarding the restoration practices of service.

 (a)  Acceptable methods of public notification. In the event of a service interruption, the following acceptable methods of public notification should be considered and utilized as appropriate:

   (1)  Mass media. Facsimile/electronic mail notification to local radio and television stations, cable systems, newspapers and other print and news media as soon as possible after the event occurs. These notifications must provide relevant information about the event, such as the affected locations, its potential impact including the possible duration of the outage, and a description of actions affected ratepayers/occupants should take to ensure their safety, with updates as often as needed. Updates should be provided on a predictable, regular schedule for the duration of the event. The Commission’s Office of Communications and Emergency Preparedness Coordinator should also receive these notifications.

   (2)  Web site. Use of the utility’s own Internet web site, emergency phone line and integrated voice response system to provide relevant information about the event, such as the affected locations, its potential impact and estimated duration, and a description of actions affected ratepayers/occupants should take to ensure their safety, with updates as often as needed. A section of the utility’s web site shall be dedicated to presenting outage information where regular updates of the number of customers without service by geographic area and estimated restoration times are available. Depending on natural gas distribution company (NGDC) system limitations, this could be as simple as a PDF or spreadsheet file of information that is updated at regular intervals.

   (3)  Automated dialer system. Automated dialer system (outbound dialing) notification to affected ratepayers’/occupants’ landline or wireless phones. Updates should be provided at regular intervals or if the estimated restoration time changes by more than 2 hours.

   (4)  Miscellaneous. Other types of direct or actual notice, such as doorknob flyers distributed to affected ratepayers/occupants with actions affected ratepayers/occupants should take to ensure their safety, when feasible.

   (5)  Electronic mail and other emerging technology. Electronic mail and text message notification to affected customers who have opted to receive notice through use of these methods. The use of emerging technology such as social media is strongly encouraged.

   (6)  Emergency alert system. Coordination with State and local emergency management agencies as needed to use the emergency alert system for qualifying situations.

 (b)  NIMS standards. Utilities should strive to follow the National Incident Management System (NIMS) and its public information system to organize all information throughout the utility into one unified message.

   (1)  Crisis communication plans. NGDC crisis communications plans should be in writing and every attempt should be made to be consistent with Nationally-approved NIMS standards. NGDCs required to have written emergency plans under United States Department of Transportation regulations should also be familiar with NIMS standards so that NGDCs will be able to coordinate and respond under this paragraph and paragraphs (2) and (3).

   (2)  Coordination. If more than one NGDC is affected in the same geographic region, strong consideration should be given to implementing the NIMS based Joint Information System/Joint Information Center, including coordinating messages on safety and other consumer information tips during outages. This would allow for coordination and integration of information across jurisdictions, especially on universal messages such as actions residents should take to ensure safety.

   (3)  Public notice templates. NGDCs should have public notice templates prepared in advance to be available when needed to avoid wasting critical time developing materials when confronted with an unscheduled service interruption or an emergency situation. The notices should cover many possible scenarios from safety and shelter information, estimated restoration times and times when updated information will be provided.

 (c)  Contact information. To ensure that the public is informed, if possible, utilities should consider having a knowledgeable contact person stationed in the area of the outage, if possible, during the emergency to communicate to the public and media on behalf of the company. Regular media updates should be scheduled at predictable times.

   (1)  Spokesperson. A single point of contact should be established as the sole media spokesperson for the utility for that time period. During extended outages, a secondary-media spokesperson could be utilized as the sole contact for a specific period of time.

   (2)  Talking points and informational sheets. Talking points or informational sheets should be provided to customer service representatives and others who may come in contact with the public during the course of the outage to strive toward consistency of message. This information should also be shared with the Commission’s Office of Communications, its Emergency Preparedness Coordinator and county emergency management agencies. For employees that may have contact with the public but will not be able to receive up-to-date outage information in the course of their duties, the utility should instruct those employees to direct the public to appropriate information sources.

   The provisions of this §  69.1702 adopted February 24, 2012, effective February 25, 2012, 42 Pa.B. 1034.

   This section cited in 52 Pa. Code §  69.1701 (relating to scope).

DEFAULT SERVICE AND RETAIL ELECTRIC MARKETS—STATEMENT OF POLICY

§ 69.1801. Scope.

 Sections 69.1802—69.1817 provide guidelines to default service providers regarding the acquisition of electric generation supply, the recovery of associated costs and the integration of default service with competitive retail electric markets.

   The provisions of this §  69.1801 adopted September 14, 2007, effective September 15, 2007, 37 Pa.B. 5019.

 (a)  The Commission has adopted regulations governing the default service obligation in § §  54.181—54.189 (relating to default service), as required by 66 Pa.C.S. §  2807(e) (relating to duties of electric distribution companies). The regulations address the elements of a default service regulatory framework. The goal of the default service regulations is to ensure that each DSP provides default service customers with adequate and reliable service at the least cost to customers over time. This goal can be accomplished by structuring default service in a way that brings competitive market discipline to historically regulated markets and by encouraging the entry of new retail and wholesale suppliers. Greater diversity of suppliers will benefit ratepayers and the Commonwealth. However, those rules are not designed to resolve every possible issue relating to the acquisition of electric generation supply, the recovery of reasonable costs, the conditions of service and the relationship with the competitive retail market.

 (b)  The Commission is very cognizant of the practical limits of regulating large, complex markets. Changes in Federal or State law, improvements in technology, and developments in wholesale energy markets may render obsolete any all-inclusive regulatory approach to this Commonwealth’s retail electric market.

 (c)  The Commission has devised an approach that will allow this Commonwealth to adapt to changes in energy markets and the regulatory environment. The regulations in Chapter 54 (relating to electricity generation customer choice) will serve as a general framework for default service and provide an appropriate measure of regulatory certainty for ratepayers and market participants. This section and § §  69.1801 and 69.1803—69.1817 will provide guidelines on those matters when a degree of flexibility is required to respond effectively to regulatory and market challenges. The Commission anticipates that the initial guidelines will be applied to the first set of default service plans following expiration of the generation rate caps, and that the guidelines will be reevaluated prior to the filing of subsequent default service plans.

   The provisions of this §  69.1802 adopted September 14, 2007, effective September 15, 2007, 37 Pa.B. 5019; amended February 24, 2012, effective February 25, 2012, 42 Pa.B. 1044. Immediately preceding text appears at serial pages (330091) to (330092).

 The following words and terms, when used in this section and § §  69.1801, 69.1802 and 69.1804—69.1817, have the following meanings, unless the context clearly indicates otherwise:

   Alternative energy portfolio standards—A requirement that a certain percentage of electric energy sold to retail customers in this Commonwealth by EDCs and EGSs be derived from alternative energy sources, as defined in the Alternative Energy Portfolio Standards Act (73 P. S. § §  1648.1—1648.8).

   Bilateral contract—The term has the same meaning as defined in 66 Pa.C.S. §  2803 (relating to definitions).

   Competitive bid solicitation process—A fair, transparent and nondiscriminatory process by which a DSP awards contracts for electric generation to qualified suppliers who submit the lowest bids.

   DSP—Default service provider—The term has the same meaning as defined in 66 Pa.C.S. §  2803.

   Default service—Electric generation supply service provided pursuant to a default service program to a retail electric customer not receiving service from an EGS.

   Default service implementation plan—The schedule of competitive bid solicitations and spot market purchases, technical requirements and related forms and agreements.

   Default service procurement plan—The electric generation supply acquisition strategy the DSP will utilize in satisfying its default service obligations, including the manner of compliance with the alternative energy portfolio standards requirement.

   Default service program—A filing submitted to the Commission by the DSP that identifies a procurement plan, an implementation plan, a rate design to recover all reasonable costs and all other elements identified in §  54.185 (relating to default service programs and periods of service).

   EDC—Electric distribution company—The term has the same meaning as defined in 66 Pa.C.S. §  2803.

   EGS—Electric generation supplier—The term has the same meaning as defined in 66 Pa.C.S. §  2803.

   Maximum registered peak load—The highest level of demand for a particular customer, based on the PJM Interconnection, LLC, ‘‘peak load contribution standard,’’ or its equivalent, and as may be further defined by the EDC tariff in a particular service territory.

   PTC—Price-to-compare—A line item that appears on a retail customer’s monthly bill for default service. The PTC is equal to the sum of all unbundled generation and transmission related charges to a default service customer for that month of service.

   RTO—Regional transmission organization—A Federal Energy Regulatory Commission (FERC)-approved regional transmission organization.

   Retail customer or retail electric customer—These terms have the same meaning as defined in 66 Pa.C.S. §  2803.

   Spot market energy purchase—The purchase of an electric generation supply product in a FERC-approved real time or day ahead energy market.

   The provisions of this §  69.1803 adopted September 14, 2007, effective September 15, 2007, 37 Pa.B. 5019; amended February 24, 2012, effective February 25, 2012, 42 Pa.B. 1044. Immediately preceding text appears at serial pages (330092) to (330093).

 The default service regulations provide for a standard initial program term of 2 to 3 years. Initial programs may vary from this standard to comply with the applicable RTO planning year. Subsequent programs should be for 2 years, unless otherwise directed by the Commission. The Commission will monitor developments in wholesale or retail markets and revisit this issue as appropriate. The Commission may revise the duration of the standard program term and program filing schedules based on market developments.

   The provisions of this §  69.1804 adopted September 14, 2007, effective September 15, 2007, 37 Pa.B. 5019.

 A proposed procurement plan should balance the goals of allowing the development of a competitive retail supply market and also including a prudent mix of arrangements to minimize the risk of over-reliance on any energy products at a particular point in time. In developing a proposed procurement plan, a DSP should consider including a prudent mix of supply-side and demand-side resources such as long-term, short-term, staggered-term and spot market purchases to minimize the risk of contracting for supply at times of peak prices. Short-term contracts are contracts up to and including 4 years in length. Long-term contracts are contracts more than 4 years in length but not more than 20 years. Long-term contracts of more than 4 years in length but not more than 20 years should not constitute more than 25% of the DSP’s projected load unless the Commission determines that a greater portion of load is necessary to achieve least cost procurement. The plan should be tailored to the following customer groupings, but DSPs may propose alternative divisions of customers by registered peak load to preserve existing customer classes.

   (1)  Residential customers and nonresidential customers with less than 25 kW in maximum registered peak load. Initially, the DSP should acquire electric generation supply for these customers using a prudent mix of resources as described in the introductory paragraph to this section. Contracts should be laddered to minimize risk, in which a portion of the portfolio changes at least annually, with a minimum of two competitive bid solicitations a year to further reduce the risk of acquisition at a time of peak prices. In subsequent programs, the mix percentage of supply acquired through long-term and short-term contracts and spot market purchases should be adjusted, depending on developments in retail and wholesale energy markets to ensure least cost to customers.

   (2)  Nonresidential customers with 25—500 kW in maximum registered peak load. The DSP should acquire electric generation supply for these customers using a mix of resources as described in the introductory paragraph to this section. Fixed-term contracts may be laddered to minimize risk, with a minimum of two competitive bid solicitations a year to further reduce the risk of acquisition at a time of peak prices. In subsequent programs, the mix percentage of supply acquired through long-term and short-term contracts and spot market purchases should be adjusted, depending on developments in retail and wholesale energy markets to ensure least cost to customers.

   (3)  Nonresidential customers with greater than 500 kW in maximum registered peak load. Hourly priced or monthly-priced service should be available to these customers. The DSP may propose a fixed-price option for the Commission’s consideration.

   The provisions of this §  69.1805 adopted September 14, 2007, effective September 15, 2007, 37 Pa.B. 5019; amended February 24, 2012, effective February 25, 2012, 42 Pa.B. 1044. Immediately preceding text appears at serial pages (330093) to (330094).

 In procuring electric generation supply for default service customers, the DSP shall comply with the Alternative Energy Portfolio Standards Act (73 P. S. § §  1648.1—1648.8) and 66 Pa.C.S. §  2814 (relating to additional alternative energy sources).

   The provisions of this §  69.1806 adopted September 14, 2007, effective September 15, 2007, 37 Pa.B. 5019; amended February 24, 2012, effective February 25, 2012, 42 Pa.B. 1044. Immediately preceding text appears at serial page (330095).

 The following guidelines will apply to competitive bid solicitation processes:

   (1)  DSPs should use standardized request for proposal documents and supplier master agreements approved by the Commission for use in the default service procurements. The Commission will review these documents and agreements on a regular basis and revise them when appropriate after consultation with stakeholders. Revisions to these documents will not be applied retroactively to existing contracts.

   (2)  The public interest would be served by the adoption of uniform criteria and processes for bidder qualification.

   (3)  Competitive bid solicitations should be structured along customer classes, consistent with the groupings identified in §  69.1805 (relating to electric generation supply procurement). Bids should be solicited for tranches of load within each customer class. Slice of system bid designs should not be utilized. However, DSPs may allow individual tranches to be stratified by soliciting separate bid prices for residential, commercial and industrial segments when there are too few customers to organize tranches along the groupings identified in §  69.1805.

   (4)  The Commission finds that a clearly optimal bid solicitation model does not exist at the current stage of wholesale market development. DSPs may utilize various competitive bid solicitation approaches, including request for proposals that result in the submission of sealed bids and real time auctions in which energy suppliers compete with each other for tranches of customer load.

   (5)  DSPs are encouraged to coordinate their competitive bidding solicitation schedules to minimize conflicts that might negatively affect the ability of suppliers to participate in multiple procurements. DSPs should coordinate their bid conferences and bidding dates to facilitate bid participation and economies of scale, yet also providing opportunities for additional wholesale bidding over reasonable time intervals.

   (6)  The Commission’s objective is to review the results of competitive bidding processes in a manner sensitive to market dynamics but that also allows it to discharge its statutory obligations. The Commission recognizes that bid prices may be negatively affected by the length of time taken for Commission review. In the default service regulations, the Commission has reserved a period of 1 business day to review the results of competitive procurements. As retail and wholesale markets mature, and as other appropriate safeguards become available, the Commission may elect to reduce the amount of time it uses to review bidding results.

   (7)  The public interest would be served by the adoption of uniform rules for the confidentiality of competitive solicitation information. Supplier participation, bid prices and retail rates may be impacted by protecting certain information, including, the identity of winning and losing bidders, the number of bids submitted, bid prices, the allocation of load among winning bidders, and the like. At the same time, the Commission recognizes that there is a legitimate public interest in knowing some of this information when there is no possibility of any prejudice to ratepayer interests.

   (8)  The competitive bid solicitation process will be monitored by an independent evaluator. The Commission may direct that this evaluator administer competitive bid solicitations to ensure the independence of the process. This independent party will be selected by the DSP in consultation with the Commission. The DSP may not have an ownership interest in the evaluator, and vice versa, and the DSP should disclose any potential conflicts of interest on the part of the evaluator during this consultation process. The Commission will review conflicts of interest and may disqualify an evaluator to ensure the independence of the position. The evaluator should have an expertise in the analysis of wholesale energy markets, including methods of energy procurement. The evaluator should monitor compliance with Commission orders relating to a default service program, confidentiality agreements and other directives. The evaluator should report all information it obtains to the Commission.

   (9)  Wholesale energy suppliers may include a significant risk premium in their competitive bids to hedge against changes in transmission rates during the term of a default service supply contract. The public interest would be served by consideration of mechanisms that allow for the tracking and automatic adjustment of transmission rates during the term of the default service supply contract in order to reduce this premium.

   The provisions of this §  69.1807 adopted September 14, 2007, effective September 15, 2007, 37 Pa.B. 5019.

 (a)  The PTC should be designed to recover all generation, transmission and other related costs of default service. These cost elements include:

   (1)  Wholesale energy, capacity, ancillary, applicable RTO or ISO administrative and transmission costs.

   (2)  Congestion costs will ultimately be recovered from ratepayers. Congestion costs should be reflected in the fixed price bids submitted by wholesale energy suppliers.

   (3)  Supply management costs, including supply bidding, contracting, hedging, risk management costs, any scheduling and forecasting services provided exclusively for default service by the EDC, and applicable administrative and general expenses related to these activities.

   (4)  Administrative costs, including billing, collection, education, regulatory, litigation, tariff filings, working capital, information system and associated administrative and general expenses related to default service.

   (5)  Applicable taxes, excluding Sales Tax.

   (6)  Costs for alternative energy portfolio standard compliance.

 (b)  EDC rates should be scrutinized for any generation related costs that remain embedded in distribution rates. This review should occur no later than the next distribution rate case for each EDC filed after September 15, 2007. The Commission may initiate a cost allocation case for an EDC on its own motion if such a case is not initiated by December 31, 2007. Changes to rates resulting from the examination would take effect after the expiration of Commission-approved rate caps.

   The provisions of this §  69.1808 adopted September 14, 2007, effective September 15, 2007, 37 Pa.B. 5019.

 (a)  Consistent with the default service regulations, default service rates, and correspondingly the PTC, may not be adjusted more frequently than on a quarterly basis for residential and small business customers to reflect changes in and ensure the recovery of reasonable costs resulting from changes in wholesale energy prices or other costs from the introduction of new, differently priced energy supply products to the DSP’s portfolio, and to correct the under and over collection of costs. This PTC adjustment may be driven by changes in spot market prices, the use of laddered contracts, the use of seasonal rate design, and the like.

 (b)  The public interest may be served if default service and alternative energy compliance costs and the revenues received through default service rates are reconciled as part of the PTC adjustment process. Reconciliation would ensure that DSPs fully recover their actual, incurred costs without requiring customers to pay more than is required. The PTC adjustment will therefore also reflect changes required due to the reconciliation of costs and revenues. Reconciliation proposals should result in a PTC adjustment that will resolve cumulative under or over recoveries by the time of the next PTC adjustment interval.

 (c)  It may be in the public interest to reconcile default service costs more frequently than at each PTC adjustment interval. The DSP should propose interim reconciliation prior to the next subsequent PTC adjustment interval when current monthly revenues have diverged from current monthly costs, plus any cumulative over/under recoveries, by greater than 4% since the last rate adjustment. When the divergence is less than 4%, the DSP has the discretion to propose interim reconciliation prior to the next PTC adjustment interval. Interim reconciliation proposals should result in a PTC adjustment that will resolve cumulative under or over recoveries by the time of the next PTC adjustment interval.

   The provisions of this §  69.1809 adopted September 14, 2007, effective September 15, 2007, 37 Pa.B. 5019; amended February 24, 2012, effective February 25, 2012, 42 Pa.B. 1044. Immediately preceding text appears at serial pages (330097) to (330098).

 Retail rates should be designed to reflect the actual, incurred cost of energy and therefore encourage energy conservation. The PTC should not incorporate declining blocks, demand charges or similar elements. The PTC for a particular customer class may be converted to a time of use design if the Commission finds it to be in the public interest.

   The provisions of this §  69.1810 adopted September 14, 2007, effective September 15, 2007, 37 Pa.B. 5019.

 (a)  The following provision should apply when a DSP’s total retail rate for a customer class rises by more than 25% following the expiration of a generation rate cap due to wholesale energy prices. When that occurs, DSPs should offer all residential and small business customers of up to 25 kW in maximum registered peak load the opportunity to prepay or defer some portion of the rate increase for as long as 3 years. These competitively neutral mitigation options should be included in the default service program filed for the period that begins with the expiration of the Commission-approved generation rate cap. Customers may not be assigned to a rate increase prepay or deferral program without their affirmative consent. DSPs would be able to fully recover the reasonable carrying costs associated with a rate increase deferral program, including associated administrative costs.

 (b)  DSPs may propose other reasonable rate mitigation strategies that would reflect the incurrence of reasonable costs.

   The provisions of this §  69.1811 adopted September 14, 2007, effective September 15, 2007, 37 Pa.B. 5019.

 The public interest would be served by common standards and processes for access to retail electric customer information and data. This includes customer names and addresses, customer rate schedule and profile information, historical billing data, and real time metered data. Retail choice, demand side response and energy conservation initiatives can be facilitated if EGSs, curtailment service providers and other appropriate parties can obtain this information and data under reasonable terms and conditions common to all service territories, that give dueconsideration to customer privacy, provide security of information and provide a customer an opportunity to restrict access to nonpublic customer information.

   The provisions of this §  69.1812 adopted September 14, 2007, effective September 15, 2007, 37 Pa.B. 5019.

 The public interest would be served by the consideration of the availability of rate and bill ready billing in each service territory.

   The provisions of this §  69.1813 adopted September 14, 2007, effective September 15, 2007, 37 Pa.B. 5019.

 The public interest would be served by the consideration of an EGS receivables purchase program in each service territory.

   The provisions of this §  69.1814 adopted September 14, 2007, effective September 15, 2007, 37 Pa.B. 5019.

 The public interest would be served by consideration of customer referral programs in which retail customers are referred to EGSs.

   The provisions of this §  69.1815 adopted September 14, 2007, effective September 15, 2007, 37 Pa.B. 5019.

 The public interest would be served by the adoption of supplier tariffs that are uniform as to both form and content. Uniform supplier tariffs may facilitate the participation of EGSs in the retail market of this Commonwealth and reduce the potential for mistakes or misunderstandings between EGSs and EDCs.

   The provisions of this §  69.1816 adopted September 14, 2007, effective September 15, 2007, 37 Pa.B. 5019.

 The public interest would be served by the designation of an employee as a retail choice ombudsman at each EDC and the Commission. The ombudsman would be responsible for responding to questions from EGSs, monitoring competitive market complaints and facilitating informal dispute resolution between the DSP and EGSs.

   The provisions of this §  69.1817 adopted September 14, 2007, effective September 15, 2007, 37 Pa.B. 5019.

   This section cited in 52 Pa. Code §  69.1801 (relating to scope); 52 Pa. Code §  69.1802 (relating to purpose); and 52 Pa. Code §  69.1803 (relating to definitions).

UTILITY SERVICE OUTAGE PUBLIC NOTIFICATION GUIDELINES—ELECTRIC DISTRIBUTION MARKET

§ 69.1901. Scope.

 This section and §  69.1902 (relating to notification guidelines) provide guidelines to the electric distribution market regarding the restoration practices of service.

 (a)  Acceptable methods of public notification. In the event of a service interruption, the following acceptable methods of public notification should be considered and utilized as appropriate:

   (1)  Mass media. Facsimile/electronic mail notification to local radio and television stations, cable systems, newspapers and other print and news media as soon as possible after the event occurs. These notifications must provide relevant information about the event, such as the affected locations, its potential impact including the possible duration of the outage, and a description of actions affected ratepayers/occupants should take to ensure their safety, with updates as often as needed. Updates should be provided on a predictable, regular schedule for the duration of the event. The Commission’s Office of Communications and Emergency Preparedness Coordinator should also receive these notifications.

   (2)  Web site. Use of the utility’s own Internet web site, emergency phone line and integrated voice response system to provide relevant information about the event, such as the affected locations, its potential impact and estimated duration, and a description of actions affected ratepayers/occupants should take to ensure their safety, with updates as often as needed. A section of the utility’s web site shall be dedicated to presenting outage information where regular updates of the number of customers without service by geographic area and estimated restoration times are available. Depending on electric distribution company (EDC) system limitations, this could be as simple as a PDF or spreadsheet file of information that is updated at regular intervals.

   (3)  Automated dialer system. Automated dialer system (outbound dialing) notification to affected ratepayers’/occupants’ landline or wireless phones. Updates should be provided at regular intervals or if the estimated restoration time changes by more than 2 hours.

   (4)  Miscellaneous. Other types of direct or actual notice, such as doorknob flyers distributed to affected ratepayers/occupants with actions affected ratepayers/occupants should take to ensure their safety, when feasible.

   (5)  Electronic mail and other emerging technology. Electronic mail and text message notification to affected customers who have opted to receive notice through use of these methods. The use of emerging technology such as social media is strongly encouraged.

   (6)  Emergency alert system. Coordination with State and local emergency management agencies as needed to use the emergency alert system for qualifying situations.

 (b)  NIMS standards. Utilities should strive to follow the National Incident Management System (NIMS) and its Public Information System to organize all information throughout the utility into one unified message.

   (1)  Crisis communication plans. EDC crisis communications plans should be in writing and every attempt should be made to be consistent with Nationally-approved NIMS standards.

   (2)  Coordination. If more than one EDC is affected in the same geographic region, strong consideration should be given to implementing the NIMS based Joint Information System/Joint Information Center, including coordinating messages on safety and other consumer information tips during outages. This would allow for coordination and integration of information across jurisdictions, especially on universal messages such as actions residents should take to ensure safety.

   (3)  Public notice templates. The EDCs should have public notice templates prepared in advance to be available when needed to avoid wasting critical time developing materials when confronted with an unscheduled service interruption or an emergency situation. The notices should cover many possible scenarios from safety and shelter information, estimated restoration times and times when updated information will be provided.

 (c)  Contact information. To ensure that the public is informed, if possible, utilities should consider having a knowledgeable contact person stationed in the area of the outage, during the emergency to communicate to the public and media on behalf of the company. Regular media updates should be scheduled at predictable times.

   (1)  Spokesperson. A single point of contact should be established as the sole media spokesperson for the utility for that time period. During extended outages, a secondary-media spokesperson could be utilized as the sole contact for a specific period of time.

   (2)  Talking points and informational sheets. Talking points or informational sheets should be provided to customer service representatives, and others who may come in contact with the public during the course of the outage to strive toward consistency of message. This information should also be shared with the Commission’s Office of Communications, its Emergency Preparedness Coordinator and county emergency management agencies. For employees that may have contact with the public but will not be able to receive up-to-date outage information in the course of their duties, the utility should instruct those employees to direct the public to appropriate information sources.

   The provisions of this §  69.1902 adopted February 24, 2012, effective February 25, 2012, 42 Pa.B. 1034.

   This section cited in 52 Pa. Code §  69.1901 (relating to scope).

INTERCONNECTION APPLICATION FEES

§ 69.2101. Statement of scope.

 Sections 69.2102—69.2104 provide guidelines to electric distribution companies and customer-generators regarding appropriate fees to be used in filing and processing interconnection applications under section 5 of the Alternative Energy Portfolio Standards Act (73 P. S. §  1648.5) regarding alternative energy and interconnection standards and § §  75.21, 75.22, 75.31—75.40 and 75.51 (relating to interconnection standards; and dispute resolution).

   The provisions of this §  69.2101 adopted April 3, 2009, effective April 4, 2009, 39 Pa.B. 1676.

 (a)  This section and § §  69.2101, 69.2103 and 69.2104 (relating to interconnection application fees) are intended to provide guidance to electric distribution companies and customer-generators seeking to interconnect with an electric distribution company’s distribution system under § §  75.21, 75.22, 75.31—75.40 and 75.51 (relating to interconnection standards; and dispute resolution). The application fees set forth under these sections are deemed appropriate. An electric distribution company which seeks to impose fees other than those set forth in §  69.2104 (relating to interconnection application fees) is required to file for Commission approval and make an evidentiary showing that deviation from these sections is appropriate.

 (b)  Electric distribution companies and entities such as industrial parks or residential developers may negotiate different fees for multiple interconnections.

   The provisions of this §  69.2102 adopted April 3, 2009, effective April 4, 2009, 39 Pa.B. 1676.

 The following words and terms, when used in this section and § §  69.2101, 69.2102 and 69.2104 (relating to interconnection application fees), have the following meanings, unless the context clearly indicates otherwise:

   Area network impact study—An engineering study conducted by an Electric Distribution Company of a local area network under §  75.40 (relating to Level 4 interconnection review).

   Customer-generator—A nonutility owner or operator of a net metered distributed generation system as defined in §  75.1 (relating to definitions).

   Facility study—A study conducted by an electric distribution company or a third party consultant for the customer-generator as defined in §  75.22 (relating to definitions).

   Feasibility study—A preliminary evaluation of the system impact and cost of interconnecting the small generator facility to the electric distribution company’s electric distribution system, as defined in §  75.22.

   Level 1 review—The interconnection application review level in §  75.37 (relating to Level 1 interconnection review).

   Level 2 review—The interconnection application review level in §  75.38 (relating to Level 2 interconnection review).

   Level 3 review—The interconnection application review level in §  75.39 (relating to Level 3 interconnection review).

   Level 4 review—The interconnection application review level in §  75.40 (relating to Level 4 interconnection review).

   System impact study—An engineering study that evaluates the impact of the proposed interconnection on the safety and reliability of an electric distribution company’s electric distribution system, as defined in §  75.22.

   The provisions of this §  69.2103 adopted April 3, 2009, effective April 4, 2009, 39 Pa.B. 1676.

 The following fee structures and fees will be deemed appropriate for use by electric distribution companies when processing interconnection applications filed under § §  75.21, 75.22, 75.31—75.40 and 75.51 (relating to interconnection standards):

   (1)  Level 1 applications—$100. If an application is denied because it does not meet the requirements of a Level 1 review, and the applicant resubmits the application under another review procedure in accordance with this title, the electric distribution company may impose a fee for the incremental expense attributable to the resubmitted application consistent with the fees established for the new level of review.

   (2)  Level 2 applications. Base fee of $250 plus $1 per kW of the nameplate capacity rating of the customer-generator’s facility, plus the cost of any minor modifications to the electric distribution company’s distribution system or additional review if required under §  75.38 (relating to Level 2 interconnection review). Costs for minor modifications or additional review must be based on electric distribution company estimates and must be subject to review by the Commission at the request of either party. Costs for engineering work done as part of any additional review should not exceed $100 per hour. If an application is denied because it does not meet the requirements of a Level 2 review, and the applicant resubmits the application under another review procedure in accordance with this title, the electric distribution company may impose a fee for the incremental expense attributable to the resubmitted application consistent with the fees established for the new level of review.

   (3)  Level 3 applications. Base fee of $350 plus $2 per kW of the nameplate capacity rating of the customer-generator’s facility, plus the cost of any feasibility studies, system impact studies or facilities studies required under §  75.39 (relating to Level 3 interconnection review). Costs for engineering work done as part of a feasibility study, system impact study or facilities study should not exceed $100 per hour. If the electric distribution company must install facilities to accommodate the interconnection of the customer-generator facility, the cost of the facilities shall be the responsibility of the customer-generator. If an application is denied because it does not meet the requirements of a Level 3 review, and the applicant resubmits the application under another review procedure in accordance with this title, the electric distribution company may impose a fee for the incremental expense attributable to the resubmitted application consistent with the fees established for the new level of review.

   (4)  Level 4 applications. In those instances when a Level 4 application is processed using the Level 1, Level 2 or Level 3 review process, the fees set forth for those particular review levels should apply. A fee may not be assessed for an area network impact study conducted under §  75.40 (relating to Level 4 interconnection review). A Level 4 application reviewed under §  75.40(d) should be subject to a base fee of $350 plus $2 per kW of the nameplate capacity rating of the customer-generator’s facility. If an application is denied because it does not meet the requirements of a Level 4 review, and the applicant resubmits the application under another review procedure in accordance with this title, the electric distribution company may impose a fee for the incremental expense attributable to the resubmitted application consistent with the fees established for the new level of review.

   The provisions of this §  69.2104 adopted April 3, 2009, effective April 4, 2009, 39 Pa.B. 1676; corrected July 10, 2009, effective July 11, 2009, 39 Pa.B. 3471. Immediately preceding text appears at serial pages (342485) to (342486).

   This section cited in 52 Pa. Code §  69.2101 (relating to statement of scope); 52 Pa. Code §  69.2102 (relating to statement of purpose); and 52 Pa. Code §  69.2103 (relating to definitions).

COMMONWEALTH REQUIREMENTS FOR DESIGNATION
AND ANNUAL RECERTIFICATION AND REPORTING REQUIREMENTS OF ELIGIBLE TELECOMMUNICATION
CARRIERS FOR PURPOSES OF FEDERAL UNIVERSAL
SERVICE SUPPORT—STATEMENT OF POLICY

§ 69.2501. Standards applicable for designation and annual certification as an eligible telecommunications carrier, for purposes of obtaining Federal universal service support.

 (a)  Petitions for designation in this Commonwealth as an eligible telecommunications carrier (ETC), for purposes of obtaining Federal universal service support, should be evaluated under:

   (1)  Section 214(e) of the Telecommunications Act of 1934 (47 U.S.C. §  214(e)), regarding extension of lines or discontinuance of service; certificate of public convenience and necessity.

   (2)  The Federal Communications Commission’s (FCC’s) discussion of ETC designations in the Universal Service Order, Report and Order at CC Docket No. 96-45 (May 8, 1997).

   (3)  The standards in the FCC’s Report and Order at CC Docket No. 96-45 (March 17, 2005).

   (4)  The FCC’s rules governing ETC designations in 47 CFR 54.101, 54.201—54.203 and 54.205—54.209.

 (b)  Petitions for designation as an ETC seeking low income support from Lifeline and Link-up America programs should satisfy the minimum standards established in 66 Pa.C.S. §  3019(f) (relating to lifeline service) and comply with the Commission’s Lifeline and Link-Up Order, In Re: Lifeline and Link-Up Programs, Docket No. M-00051871, Final Order May 23, 2005, except that verifications should be submitted annually to Universal Service Administrative Company (USAC) on or before August 31 of each year. Petitions should affirm that the applying carrier will submit annual Lifeline Tracking Reports by June 30 of each year. The form is available on the Commission’s web site at www.puc. state.pa.us, Online Forms, Telecommunications.

 (c)  Petitions for ETC designation should specifically address the enumerated criteria in subsections (a) and (b), set forth specific statements regarding which criteria are applicable and inapplicable, and explain why all applicable criteria are satisfied.

   The provisions of this §  69.2501 adopted October 1, 2010, effective October 2, 2010, 40 Pa.B. 5586.

APPLICATION OF PGW CASH FLOW RATEMAKING
METHOD—FINAL STATEMENT OF POLICY

§ 69.2701. Definitions.

 The following words and terms, when used in this section and § §  69.2702 and 69.2703, have the following meanings, unless the context clearly indicates otherwise:

   Act—The Natural Gas Choice and Competition Act (66 Pa.C.S. § §  2201—2212).

   PGW—Philadelphia Gas Works.

 (a)  The act brought city owned natural gas operations, including PGW, under the Commission’s jurisdiction. See 66 Pa.C.S. §  2212(b) (relating to Commission jurisdiction).

 (b)  The Commission is obligated under law to use the cash flow methodology to determine PGW’s just and reasonable rates. Included in that requirement is the subsidiary obligation to provide revenue allowances from rates adequate to cover its reasonable and prudent operating expenses, depreciation allowances and debt service, as well as sufficient margins to meet bond coverage requirements and other internally generated funds over and above its bond coverage requirements, as the Commission deems appropriate and in the public interest for purposes such as capital improvements, retirement of debt and working capital.

   The provisions of this §  69.2702 adopted May 21, 2010, effective May 22, 2010, 40 Pa.B. 2668.

 (a)  In determining just and reasonable rate levels for PGW, the Commission will consider, among other relevant factors:

   (1)  PGW’s test year-end and (as a check) projected future levels of non-borrowed year-end cash.

   (2)  Available short term borrowing capacity and internal generation of funds to fund construction.

   (3)  Debt to equity ratios and financial performance of similarly situated utility enterprises.

   (4)  Level of operating and other expenses in comparison to similarly situated utility enterprises.

   (5)  Level of financial performance needed to maintain or improve PGW’s bond rating thereby permitting PGW to access the capital markets at the lowest reasonable costs to customers over time.

   (6)  PGW’s management quality, efficiency and effectiveness.

   (7)  Service quality and reliability.

   (8)  Effect on universal service.

 (b)  The Commission is obligated to establish rate levels adequate to permit PGW to satisfy its bond ordinance covenants, consistent with 66 Pa.C.S. §  2212(e) (relating to securities of city natural gas distribution operations).

 (c)  These financial measures will be considered by the Commission in determining just and reasonable rates for PGW under 66 Pa.C.S. (relating to the Public Utility Code) and are consistent with the PGW Management Agreement Ordinance.

   The provisions of this §  69.2703 adopted May 21, 2010, effective May 22, 2010, 40 Pa.B. 2668.

   This section cited in 52 Pa. Code §  69.2701 (relating to definitions).

PENNSYLVANIA SOLAR PROJECTS

§ 69.2901. Purpose.

 (a)  Beginning in 2004, the General Assembly enacted, and the Governor signed, a series of legislation promoting the development of renewable energy in this Commonwealth generally, and solar alternative energy specifically. In 2004, the AEPS Act established a requirement that the power purchased for customers in this Commonwealth by EDCs and EGSs must include a component of solar photovoltaic electricity from solar alternative energy sources or solar alternative energy credits, known in the industry as SRECs. Under the AEPS Act, an SREC is referred to as a solar alternative energy credit, or solar Alternative Energy Credit (AEC). An AEC is earned when 1 megawatt hour of electricity is generated from an approved alternative energy source. In 2007, the AEPS Act was amended and, among other provisions, solar thermal energy was added to the definition of Tier I alternative energy sources. The Commission is responsible for ensuring compliance with the AEPS Act.

 (b)  In 2008, the Alternative Energy Investment Act (AEI Act) (73 P. S. § §  1649.101—1649.711) was signed into law, providing, among other things, funding through the Department of Environmental Protection for small-scale solar projects in owner-occupied dwellings and small businesses. Additional funds for large-scale solar projects were made available by the AEI Act through the Department of Community and Economic Development (DCED).

 (c)  These acts establish a clear policy to promote the construction of small- and large-scale solar projects in this Commonwealth. Even though that policy has been clearly articulated, the Commission is concerned that barriers still exist that prevent new solar projects from becoming a reality in this Commonwealth. EDCs in this Commonwealth, their customers and those interested in developing solar projects of any size are impeded in their economic analysis of those projects by the uncertainty of a price to assign the SRECs that would be generated by small- or large-scale solar projects. This section and § §  69.2902—69.2904 (relating to definitions; RFPs to establish SREC values recoverable as a reasonable expense; and contracts for the purchase of SRECs by EDCs) outline a process by which entry barriers can be overcome.

   The provisions of this §  69.2901 adopted October 22, 2010, effective October 23, 2010, 40 Pa.B. 6157.

 The following words and terms, when used in § §  69.2901, 69.2903 and 69.2904, have the following meanings, unless the context clearly indicates otherwise:

   AEPS Act—The Alternative Energy Portfolio Standard Act (73 P. S. § §  1648.1—1648.8).

   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.

   Large-scale solar project—An alternative energy generation system employing solar photovoltaic technology with a nameplate capacity of 200kW or more.

   RFP—Request for proposal.

   SREC market price—The weighted average of all accepted winning bids in response to an EDC RFP for large-scale solar project solar alternative energy credits, as those credits are defined in section 2 of the AEPS Act (73 P. S. §  1648.2).

   SRECs—Solar renewable energy credits.

   Small-scale solar project—An alternative energy generation system employing solar photovoltaic technology with a nameplate capacity of less than 200kW.

   Solar aggregator—A person or entity that purchases for resale, or otherwise consolidates for sale, solar alternative energy credits for resale to EDCs and electric generation suppliers.

   Stakeholder working group—A group composed of EDCs, EGSs, Commission staff, public advocates, solar aggregators and other interested parties that meets at least semiannually and proposes to the Commission updates to standardized solar alternative energy credit RFPs and related contracts that are posted on the Commission’s web site.

   The provisions of this §  69.2902 adopted October 22, 2010, effective October 23, 2010, 40 Pa.B. 6157.

 (a)  SREC procurement from large-scale solar projects. The Commission encourages EDCs to issue RFPs for large-scale solar projects whose SREC output will be used to meet EDC obligations under the AEPS Act. RFPs should provide for a fair, transparent and open competitive bidding process. Standardized RFP documents developed by the stakeholder working group should be utilized. The Commission will review and either approve or reject bids submitted in response to the RFPs within a reasonable period of time.

 (b)  SREC procurement from small-scale solar projects. EDCs are encouraged to procure SRECs from small-scale solar projects through competitively bid RFP processes and bilateral contracts.

   (1)  When an RFP process is used, EDCs should adhere to the same standards in use for large-scale solar project RFPs. The Commission will review and evaluate bids for small-scale solar RFPs within a reasonable period of time.

   (2)  EDCs may enter into bilateral contracts for SRECs from small solar projects subject to the following conditions:

     (i)   The price negotiated for SRECs should not exceed the Commission-approved average winning bid price in the EDC’s most recent RFP for large-scale solar projects.

     (ii)   When an EDC has not utilized an RFP for a large-scale project, the price negotiated for SRECs should not exceed the Commission-approved average winning bid price from the most recent large-scale solar RFP by another EDC in this Commonwealth, as reported on the Commission’s AEPS Credit Administrator’s web site under subparagraph (iii).

     (iii)   The amount of small-scale solar project SRECs yet to be procured by the EDC, and the EDC’s historic and current average SREC market prices from each of the EDC’s large solar project procurements should be listed on the Commission’s AEPS Credit Administrator’s web site, as well as the EDC’s web site, and updated at least monthly.

     (iv)   The bilateral contract approach should be used to support the development of small-scale solar projects located in this Commonwealth.

 (c)  EDC cost recovery. The cost of SRECs acquired through procurement approaches referred to in subsections (a) and (b) may be recovered consistent with the AEPS Act and other applicable law.

   The provisions of this §  69.2903 adopted October 22, 2010, effective October 23, 2010, 40 Pa.B. 6157.

 (a)  Standardized contracts. EDCs should employ standardized contracts for their purchase of SRECs from large-scale solar projects and small-scale solar projects. The standardized contract for small-scale solar projects should be simple, understandable and provide for the option to purchase SRECs from solar aggregators. Standardized contracts for the long-term procurement of SRECs should be from 5 to 20 years in length.

 (b)  Contracts with solar aggregators. The Commission finds it reasonable and efficient, and therefore encourages EDCs to execute a master agreement with a solar aggregator for the purchase of SRECs from various sources that establishes a prevailing SREC market price at a particular point in time through letter agreements that incorporate the terms of the master agreement.

 (c)  Performance guarantees, security and other contract terms. While EDCs may require the posting of bid security in an RFP for large-scale solar projects, bid security for small-scale solar projects is not necessary due to the manner in which the SREC market price for these projects is established. In addition, small-scale solar projects under 15kW in nameplate capacity may use estimates to report SREC generation to the PJM-GATS system, as authorized under the AEPS Act, and should not be required to provide security relating to project completion or performance. Small-scale solar project contracts for projects at or above 15kW in nameplate capacity, or from a solar aggregator selling the EDC SRECs from projects 15kW or more in nameplate capacity, may contain a security deposit, refundable upon completion of project construction and certification of initial performance, as well as a performance guarantee refundable over the performance period or at the end of the contract. These provisions may be included to ensure that the aggregated solar projects supporting the SRECs are actually constructed and perform as designed. Security deposits for projects 15kW or more in nameplate capacity, or aggregated projects 15kW or more in nameplate capacity, may be converted, upon reasonable advance notice by the EDC to the impacted parties, from a refund to a performance guarantee upon project completion and certification. In addition, small-scale solar project SREC contracts may provide for EDC remote monitoring of solar installations. Contracts between EDCs and others for the purchase of SRECs from small-scale solar projects may also provide for a reasonable allocation of the risk of a project failing due to force majeure-type events. EDCs may establish reasonable financial qualifications for solar aggregators from whom they purchase SRECs.

 (d)  Contracts on behalf of residential customers. EDCs are encouraged to contract for SRECs with solar aggregators that obtain SRECs from residential owners of small-scale solar projects. These projects can provide a beneficial way for those customers to cope with the volatility of electricity prices.

 (e)  Stakeholder working group. An EDC standardized contract and other related documents, for the purchase of SRECs from large-scale solar projects and small-scale solar projects should be posted on the Commission’s web site and periodically updated by means of input from a stakeholder working group to ensure that these contracts reflect the most recent developments in Pennsylvania law and energy policy.

 (f)  Customer education. An EDC is encouraged to educate its retail customers of the opportunity to sell SRECs under the large-scale solar project RFP solicitation and the small-scale solar program in support of local development of solar resources.

   The provisions of this §  69.2904 adopted October 22, 2010, effective October 23, 2010, 40 Pa.B. 6157.

   This section cited in 52 Pa. Code §  69.2901 (relating to purpose); and 52 Pa. Code §  69.2902 (relating to definitions).

INTERIM GUIDELINES FOR THE FILING OF ELECTRIC TRANSMISSION LINE SITING APPLICATIONS

§ 69.3101. Scope.

 (a)  The Commission adopts this section and § §  69.3102—69.3107 regarding the additional information that should be provided with a transmission siting application by an electric utility under § §  57.71—57.76 (relating to Commission review of siting and construction of electric transmission lines). The Commission encourages future applicants to file applications that comply with the existing regulations as supplemented by this section and § §  69.3102—69.3107 to ensure that adequate additional information is provided and to ensure the efficient and expeditious processing of transmission siting applications. In the event an applicant determines there to be a conflict between the information requested in this section and § §  69.3102—69.3107 and the existing regulations, the applicant should follow the requirements in § §  57.71—57.76.

 (b)  The Commission emphasizes that this section and § §  69.3102—69.3107 do not alter the legal standards to be met by prospective applicants under relevant provisions in 66 Pa.C.S. (relating to Public Utility Code) or the existing regulations in § §  57.71—57.76.

 (a)  Applications for electric transmission siting authority should provide the following information with the initial application for siting approval demonstrating its efforts to fully notify landowners who are either owners of land that will be purchased for the transmission project or will be subject to right of way/easement requirements:

   (1)  A Code of Conduct/Internal Practices governing the manner in which public utility employees or their agents interact with landowners along proposed rights of way.

   (2)  Copies of information provided to landowners by the public utility of any publicly disseminated notices advising landowners to contact the Commission or the Office of Consumer Advocate (OCA) in the event of improper land agent practices.

   (3)  Copies of all notices sent under §  57.91 (relating to disclosure of eminent domain power of electric utilities).

 (b)  Applicants for transmission siting authority should serve a copy of the Code of Conduct on all landowners along the proposed route whose property is to be purchased, subject to easement rights or borders the transmission corridor. The Code of Conduct should also be available on the applicant’s website.

 (c)  Applicants for transmission siting authority should provide prior notice to the Commission’s Office of Communications of informational presentations to community groups by the public utility scheduled after the filing of the transmission siting application so that the Commission, OCA and other interested parties can attend meetings or obtain copies of information being disseminated at the presentations.

   The provisions of this §  69.3102 adopted December 10, 2010, effective December 11, 2010, 40 Pa.B. 7095.

 Applicants for eminent domain authority should follow the following requirements and provide the following information as part of the application:

   (1)  Applicants for transmission siting authority should file applications for all known eminent domain authority as separate filings, but simultaneously with the associated transmission siting applications. Testimonial evidence in support of an eminent domain application should be filed with the application. Subsequent eminent domain authority applications should be filed as soon as reasonably known during the course of the transmission siting application.

   (2)  As part of an eminent domain application, the public utility applicant should present, for those properties subject to condemnation at the time the transmission siting application is filed or later in the siting proceeding, the reason for the exercise of condemnation power for each property and the precise location of the affected property. Supporting maps or legal descriptions of the property to be condemned should be supplied to the extent feasible. Submission of information pursuant to this guideline should be consistent with the filing requirements for the exercise of eminent domain powers under 26 Pa.C.S. §  302(b)(5) (relating to declaration of taking).

   (3)  A public utility transmission siting application should include a summary status report for those properties along the proposed transmission route where negotiations for either property acquisition or rights of way/easements may be ongoing. This information should be supplemented as requested by the administrative law judge or the parties during the course of the transmission siting proceeding.

   The provisions of this §  69.3103 adopted December 10, 2010, effective December 11, 2010, 40 Pa.B. 7095.

 Applications for exemption from municipal zoning requirements should provide the following information with the application:

   (1)  Copies of comprehensive land use plans, zoning ordinances and other documentation relevant to the buildings affected by the exemption request. This information may be filed in either hard copy or electronic format.

   (2)  Provision of metes and bounds or site maps of building sites.

   (3)  A procedure for providing notice to affected municipalities of the request for exemption.

   The provisions of this §  69.3104 adopted December 10, 2010, effective December 11, 2010, 40 Pa.B. 7095.

 Applications for the siting of electric transmission lines should provide the following information as part of the §  57.72(c) (relating to form and content of application) requirements:

   (1)  Transmission applicants should utilize a combination of transmission route evaluation procedures including high-level GIS data, traditional mapping (including United States Geological Survey data and compilation), aerial maps and analysis of physical site specific constraints raised by affected landowners.

   (2)  Transmission applicants should summarize the status of property acquisitions (including fee simple acquisitions and rights of way/easements) as part of the application. The applicant should provide the current status and continuing updates on property acquisition litigation or settlements during the course of the siting proceeding.

   (3)  In providing information regarding the reasonable alternative routes, the utility actively considered in its final phase of the route selection process, and the relative merits of each, in accordance with §  57.72(c)(10), the applicant should include the following information:

     (i)   The environmental, historical, cultural and aesthetic considerations of each route.

     (ii)   The proximity of these alternative routes to residential and nonresidential structures.

     (iii)   The applicant’s consideration of relevant existing rights of way.

     (iv)   The comparative construction costs associated with each route.

   (4)  With reference to the proposed route, applicants should provide a summary of efforts made to contact and solicit assistance from local governments and nongovernmental organizations regarding areas encompassed within the requirement of §  57.72(c)(8).

   The provisions of this §  69.3105 adopted December 10, 2010, effective December 11, 2010, 40 Pa.B. 7095.

 Applications for siting of electric transmission lines should include as part of the filing requirement under §  57.72(e)(7) the following information: A matrix or list showing all expected Federal, state and local government regulatory permitting or licensing approvals that may be required for the project at the time the application is filed, the issuing agency, approximate timeline for approval and current status. The applicant should provide an update on the status of the regulatory permitting/licensing approvals as the case progresses.

   The provisions of this §  69.3106 adopted December 10, 2010, effective December 11, 2010, 40 Pa.B. 7095.

 (a)  Interim guidelines for the use of herbicides and pesticides. Applicants for transmission line siting authority should provide a detailed vegetation management plan that includes the following components:

   (1)  A general description of the utility’s vegetation management plan.

   (2)  Factors that dictate when each method, including aerial spraying, is utilized.

   (3)  Vegetation management practices near aquatic and other sensitive locations.

   (4)  Notice procedures to affected landowners regarding vegetation management practices.

   (5)  Provision of a copy of a landowner maintenance agreement that describes the duties and responsibilities of landowners and the utility for vegetation management to the extent utilized.

 (b)  Interim guidelines for Electromagnetic Field (EMF) impacts. Transmission siting applications should include the following: A description of the EMF mitigation procedures that the utility proposes to utilize along the transmission line route. This description should include a statement of policy approach for evaluating design and siting alternatives and a description of the proposed measures for mitigating EMF impacts.

   The provisions of this §  69.3107 adopted December 10, 2010, effective December 11, 2010, 40 Pa.B. 7095.

   This section cited in 52 Pa. Code §  69.3101 (relating to scope).