[42 Pa.B. 5185]
[Saturday, August 11, 2012]

[Continued from previous Web Page]

 4. If the Commission should adopt a provision to ensure the construction of needed generation capacity, how should the default service regulations be revised?

 This Policy question elicited a limited number of responses. In light of our response to Question No. 3, we decline to act on any of the suggestions contained herein but appreciate the input received on this important issue.

 Among the EDC parties, many indicated their primary preference would be to have no regulatory requirement addressing needed generation capacity. If such a requirement were imposed, FirstEnergy suggests the development of a competitively neutral mechanism that would allow the cost to be borne by all delivery service customers.

 Among the generator parties, PPL Energy questioned whether the Commission has the legal authority to promulgate such regulations. Exelon offers that such regulations must require DSP shareholders to assume all construction and operation costs, should not permit DSPs to enter into any contracts for new generation unless the price is less than the existing market price for power, must specify a competitive process based on lowest cost to customers and require new resources to be integrated in a way that does not frustrate wholesale market rules. Constellation cautions that if the Commission forges ahead with such regulations, that the requirements for new generation be narrowly tailored to seek only products that are appropriate to the need identified and that the costs for resources should be allocated to appropriate transmission customers in specific transmission regions.

 OCA notes that the implementation of such regulation must be considered in light of the current regulatory prohibitions that a DSP's procurement cannot be from a generating unit with a specific fuel type and that DSPs are prohibited from procuring power from new generation only. OCA reminds the Commission that it is not prohibited from requiring DSPs to design long-term competitive procurements, e.g. long-term contracts, that facilitate new construction in order to ensure adequate and reliable service.

 In light of our determination made in response to Question 3 and the very valid legal and policy concerns raised in response to both Questions 3 and 4, we decline for the time being to take further action regarding additional default service regulations that would ensure the construction of needed capacity in Pennsylvania. However, we reserve the option of revisiting the issue should market conditions dictate.

 5. Which approach to supply procurement—a managed portfolio approach or a full requirements approach—is more likely to produce the least cost to customers over time?

 This question generated significant debate among the commenting parties.

 PPL explained the difference between the two approaches as follows:

Both approaches, full requirements and managed portfolio, can produce the least cost to customers over time; however, allocation of the risks and costs associated with the supply for each approach must be considered. In the full requirements approach, the default service provider procures all the energy needs for the default service customers at a fixed price. Under this approach, all the associated risks are borne by the full-requirements suppliers, such as changes in load shape, migration of customers to and from default service, and changes in market prices for energy, capacity, ancillary services, and alternative energy credits to meet the default service supply obligation. PPL Electric has employed the full requirements approach.

A managed portfolio approach includes purchasing and/or selling physical and financial products based on market and default supply conditions. In other words, the DSP is active in the market at all times to manage the risks described above (changes in load shape, migration of customers to and from default service, and changes in market prices for energy, capacity, ancillary services, and alternative energy credits). These risks and associated costs are borne by the DSP and are ultimately passed on to the default service customers. For example, if more customers migrate from default service than anticipated, the DSP may have too much supply, which can be sold in the spot market. However, the price received for those sales could be higher or lower than the price paid to purchase the supply initially. To manage these risks, the DSP would need expertise in trading in the commodity markets, which is not a core business function. Additional costs would be incurred to acquire this expertise resulting in higher default service costs.

Under a full requirements approach, the winning supplier essentially employs a managed portfolio approach to supply the default service customers. The full requirements supplier is active in the commodities markets and has the necessary expertise to manage these risks.

Neither approach, full requirements nor managed portfolio, eliminates any of these risks or costs. Rather, the risks and costs are simply shifted between suppliers and customers. Any effort to compare these two approaches must, of necessity, track the results that would be produced by each over the same period of time and under identical conditions. Because the fundamental difference between the two approaches is an assessment of risk based on imperfect information, it is essential that any such comparison reflect real-time decision-making and not hindsight.

(PPL Comments, pp. 8-10).

 Other EDCs utilize the full requirements (FR) approach. Allegheny considers its FR approach as a form of managed portfolio (MP) because customers get the benefit of service based on ''the best pieces of many managed portfolios.'' FirstEnergy states there is clear evidence, in its opinion, that the MP approach shifts the volumetric risk associated with default service supply from suppliers to buyers of default service leaving them more exposed to price volatility than does the laddered portfolio of full requirements contracts. FirstEnergy submits that requiring EDCs to time the market is unlikely to produce the least cost to customers over time and may require additional EDC infrastructure and employees to conduct the managed portfolio activity. Duquesne opines that the supply procurement method should be left up to the discretion of the DSP and the Commission's regulations should remain flexible and consider the appropriate approach on a case by case basis.

 PECO highlights the fact the Commission has approved both types of procurement processes at various times and should maintain a flexible ''case by case'' approach in light of the specific circumstances of each DSP and its customers. However, on balance, FR suppliers manage their own risk whereas the MP approach shifts the risk from suppliers to customers. PECO concludes that FR procurement approaches are better positioned to manage risk and this approach should remain an option in designing future default service plans.

 Citizens/Wellsboro, alone among the EDCs, argues in favor of the MP approach as more likely to produce least cost to customers over time for DSPs serving a small territory. Citizens/Wellsboro takes issue with other parties' support for the full requirements standard in its Reply Comments.

 Generator parties support the FR approach. P3 states that EDCs should be ''outcome neutral purchasers'' for their customers who do not choose a competitive supplier. PPL Energy advances the concern that, for an EDC to pursue a MP approach, it would have to actively manage a portfolio of power supply products and do so at a lower cost than the market. An MP approach may result in commodity positions by the EDC that creates a volumetric and price exposure resulting in higher prices to customers. Exelon notes that both approaches are difficult to compare but that the intent of Act 129 to produce least cost and price stability militates toward a ''prudent mix of standard and full requirements products.'' Constellation explains in great detail its internal processes associated with supply procurement-functions that would be difficult and expensive for an EDC to duplicate including the need to employ experienced personnel.

 FES, in Reply Comments, believes that a FR solicitation is the best method of supply procurement but that no ''one size fits all'' approach that will work in every market. FES asserts that each DSP should be able to work with stakeholders in default supply proceedings to craft a solution that balances competing interests. FES states that an MP approach entails an unjustifiably high level of risk and is not appropriate for default supply procurement. If the Commission were to implement an MP approach, FES believes that no after the fact review process should be imposed as part of that process.

 RESA also endorses the FR model. RESA considers the FR approach, if properly structured and without an overreliance on long term contracts, to be the best way to achieve the goals of the Competition Act. Under the FR approach, the wholesale supplier bears the risk of customer migration, weather, load variation and economic activity and factors the costs of these risks into a risk premium. If the risk premium is not sufficient to cover ultimate cost, the supplier cannot seek additional cost recovery from the customer or the DSP. Alternatively, the MP approach places all the management and market timing risk on customers and reflects the cost of bearing that risk in the default service rate. Under the MP model, it is virtually impossible, in RESA's view, to assume that a utility portfolio manager will outperform the wholesale supply manager. While RESA has a clear preference for the FR approach, it is possible to construct a managed portfolio plan that minimizes customer risk and requires all direct and indirect procurement costs are recovered. RESA recommends more short-term block purchases and spot purchases.

 OCA advocates reliance on the MP approach for the following reasons:

1. OCA has long advocated for the MP approach because it has not seen any empirical evidence indicating the superiority of the FR approach.

2. The FR approach shifts risks to third party suppliers who are compensated by customers for the risk associated with variation of load and other risk factors that are factored into the winning bid. Suppliers also add in additional profit margins over and above the margins factored in to compensate full requirements middlemen.

3. Under the MP approach, the DSP can directly access the generation products in the wholesale market without the need to pay an additional level of profit.

4. OCA opines that recent procurements demonstrate that the MP approach is a lower cost alternative to the FR approach. In support, OCA cites to recent procurements by PPL, PECO and FirstEnergy affiliates where the winning bids for block energy purchases was significantly less than full requirements purchases. Therefore block and spot purchase should be part of a prudent mix of products for default service.

5. OCA cites to a movement away from the FR approach based on recent procurement results from Illinois and New Jersey.

(OCA Comments, pp. 12-19).

 OSBA makes the following points: (1) there are fundamental economic differences between the FR and MP approach; (2) there are advantages and disadvantages to both methods; (3) the Commission has previously expressed preference for the FR approach but encourages further EDC study of the MP approach; and (4) there is not enough empirical evidence to support the definitive use of one method over the other.

 In their Reply Comments, Citizens/Wellsboro takes issue with many of Constellation's initial comments and requests the Commission recognize that an MP procurement standard has worked well and has enabled it to manage certain congestion events.

 PECO, in its Reply Comments, disputes the validity of OCA's reliance on the procurement results in Illinois and New Jersey as being supportive of the MP approach. PECO alleges these programs can be distinguished based on the state-specific circumstances that underlay their development. As to the evidence offered by OCA in recent EDC procurements, supporting the MP approach, PECO seizes on OCA's admission that ''comparisons of block and full requirements products cannot be made on a direct comparison basis because block purchases do not include all attributes required for default service supply and do not reflect all costs to consumers.'' Additionally, PECO highlights the fact that block price purchased power will vary based on the timing of purchases, delivery locations and ratemaking differences.

 OCA filed extensive Reply Comments in support of the MP procurement approach reiterating the following points:

1. Under the MP approach, each DSP will procure power directly from the wholesale market through a variety of products tailored to specific load.

In order to balance the precise load, the DSP would access the energy balancing services of spot purchases and sales. A portfolio approach provides the default service provider with the latitude needed to procure products available to meet its least cost obligation.

2. The MP approach will allow the DSP to lower the cost of its supply portfolio when customers participate in Act 129's energy efficiency, demand response and time of use programs.

3. The FR approach shifts the obligation to meet default service load to third party suppliers who are obligated to meet default service to a set percentage of default load regardless of the level of retail shopping that takes place in the service territory. The risks associated with the variation in load are assigned a risk premium cost by bidders that are priced into the winning bids and paid for by default service customers. These profit margins are in addition to the profit margins the generation suppliers build into their supply of the products to FR middlemen.

4. Under the MP approach, the DSP can directly access the generation products available in the wholesale market without the need to pay an extra level of profit and risk premiums to FR suppliers. There is no empirical evidence that the FR approach produces the least cost product.

5. Constellation is in error in saying the MP approach requires the DSP to time the market.

6. The experience of Citizens/Wellsboro with the MP approach is proof the MP approach is superior. Also, EDCs have managed to recently procure block and spot purchases directly at prices that were less than their FR purchases for the same period.

7. The MP approach is most consistent with both the supply and demand aspects of Act 129. A portfolio approach allows the discretion to include a variety of resources and products and affords the flexibility to incorporate new products into the supply mix such as energy efficiency, demand response, smart meter and TOU requirements to customers.

(OCA Reply Comments, pp. 3-10).

 RESA responds to OCA's arguments in support of the MP approach as follows:

1. OCA, in advocating the MP approach, never explains how this approach will impact the development of the competitive market.

2. Default service customers will be required to pay all of the costs associated with building an EDC infrastructure necessary for EDCs to perform all functions associated with MP approach.

3. Requiring EDCs to perform the MP function ignores the fact that wholesale suppliers compete with each other to win a supply contract and have an incentive to drive down costs as low as possible insulating customers from being forced to pay over inflated or unreasonable costs.

4. OCA fails to address how default service customers are benefitted when they are forced to pay the full costs of unforeseen risks under the MP method. Under the MP approach, default service customers pay the full cost of future risks where the EDC fails to perform. Under the FR approach, there is an insurance component built into the supply contract that insulates default service customers from those risks.

5. OCA fails to explain how an EDC can adequately take on, as a core business function, the role of active portfolio manager.

(RESA Reply Comments, pp. 9-13).

 This is indeed a complex and difficult issue. We appreciate the efforts the parties make in their comments to explain the advantages and disadvantages of the FR and MP methods. The question that we must address is whether we should be encouraging EDCs, as default suppliers, to be adopting, as a core function, the responsibility to act as a portfolio manager for procurement of their default supply - a function that has traditionally been the province of the electric supplier.

 The major benefit associated with the FR approach is that the procurement function is delegated to the electric supplier which is presumably better equipped with the necessary personnel and infrastructure to perform the activities associated with acquiring electric supplies in the complex and ever changing wholesale market environment. The FR process insulates default supply customers from the volatility associated with wholesale market conditions with the supplier bearing the risks of factors such as customer migration, weather, load variation and economic activity. For assuming these risks and performing the portfolio manager function, the supplier charges a risk premium (or profit) that is factored into the winning bids and paid for by default service customers.

 Alternatively, the MP approach shifts the obligation to meet default service requirements to the EDC to procure power directly from the wholesale market essentially supplanting the role of the electric supplier. Under the MP approach, the EDC becomes an active market participant with the responsibility to manage risks such as changes in load shape, customer migration to and from default service and changes in prices for capacity, energy and other ancillary services as well as the vagaries of weather and economic conditions. Instead of being insulated from the impacts of these risks, default service customers are directly exposed to the impacts of the EDCs expertise in managing its portfolios.

 Most Pennsylvania EDCs have preferred the FR approach given the balance of risks and rewards. Electric suppliers understandably favor this approach as it is their core business function - a function largely the result of electric deregulation under the Competition Act. One utility, Citizens/Wellsboro, has successfully utilized the MP approach to the benefit of its customers. Recent plans, as pointed out by OCA, have been approved which have included spot and block purchases resulting in lower prices than under the FR approach. This fact, argues OCA, coupled with experiences in New Jersey and Illinois, the potential for excess profits to generation suppliers as well as the lack of empirical evidence that the FR approach is more cost effective than the MP approach militates in favor of the MP approach. In contrast to OCA's position, RESA opines that suppliers cannot seek additional cost recovery from the customer or the DSP if the risk premium is not sufficient to cover the cost of procured power.

 On balance, we are not persuaded that the MP approach is superior to the FR approach in achieving the ''least cost to customers'' while also achieving the other objectives of ''prudent mix'' of products and price stability. The MP approach has clear advantages to the retail markets and the retail customer provided the EDC is capable of performing the full range of portfolio management functions. Based on the uniformity of comments received from those parties that actually perform these functions, the EDCs and electric suppliers, we do not feel confident in expressing a preference for the MP method at this time as the preferred means of default supply procurement. Our principal concerns are that EDCs do not currently possess the requisite expertise and infrastructure to perform these portfolio management duties and the risks to retail customers from EDC inexperience in performing these functions is too great. We are also mindful of the fact that the current default supply process, with the EDC acting as the default supplier and distribution entity purchasing its supply from electric suppliers knowledgeable about the workings of the wholesale electric market, is a product of the Competition Act, which created the market structure we now operate within. Requiring DSPs to adopt the role of electric market portfolio manager may be inconsistent with our charge under the Competition Act. Finally, we note here that, after the restructuring of the electric utility industry in Pennsylvania mandated by the Competition Act, generation planning and management is no longer a core function of an EDC's business. As such, to impose MP duties would tend to divert management attention from the EDC's core function of providing safe, reliable and adequate delivery of electric generation service.

 Consequently, we will not require nor do we specifically endorse the use of the MP approach at this time. We do express a preference for continued reliance by DSPs on the FR approach to the extent this method best suits the DSP's particular procurement needs. DSPs are, of course, free to modify their procurement methodologies as necessary to incorporate aspects of the MP approach where appropriate given the level of confidence the DSP has in its own ability to perform the portfolio management function, the DSP's customer characteristics and usage patterns and the service territory.

 We will continue to evaluate default service plans on a ''case by case'' basis recognizing that the maximum degree of flexibility given to EDC DSPs has proven to produce the best results for customers. Further, we encourage utilities such as Citizens/Wellsboro to continue to utilize those procurement methodologies that best meet the needs of its customers and which comply with the required standards under our regulations.

 6. What is a ''prudent mix'' of spot, long-term, and short-term contracts?

 What constitutes a ''prudent mix'' of contracts was subject to a number of varying definitions. Among the EDCs, PPL, PECO and FirstEnergy did not specify fixed percentages. PPL's position is that the DSP should have the discretion to propose a mix of contracts that is appropriate based on the characteristics of its customers. Moreover, there are an infinite number of procurement plans that can be considered ''prudent'' and the DSP review process allows all parties to weigh in on the subject. PPL cautions, however, that once the Commission has approved a plan, the mix of contracts should remain in place for the term without alteration. FES agrees with this position in its Reply Comments. FirstEnergy notes that the ''prudent mix'' of contracts must focus on low cost, comply with Act 129 requirements and include an acceptable amount of risk. While default service rules require a separate portfolio for each class, EDCs should not be required to offer all types of contracts (long, intermediate, short, spot) for each customer class.

PECO states as follows:

1) ''Prudent mix'' is linked to ''least cost'' and should take into account benefits of price stability.

2) A ''prudent mix'' of contracts will differ for each customer class.

3) The ''prudent mix'' of contracts may vary in the future as wholesale and retail markets evolve.

4) The degree to which a ''prudent mix'' of contracts will ensure adequate and reliable service will be influenced by such factors as contract and credit requirements.

5) The Commission should not place unnecessary constraints on the definition of ''prudent mix.''

(PECO Comments, pp. 13-15).

 Duquesne supports leaving the ''prudent mix'' of contracts definition to be determined on a ''case by case'' basis but has determined fixed percentages of products to be an optimal ''prudent mix'' for its own purposes. Allegheny recommends specific percentages of contract types for service to its customer classes.

 Among the generator parties, Exelon and Constellation advocate for a ''case by case'' determination based on the needs and characteristics of the customer class. PPL Energy offers the perspective that a ''prudent mix'' should consist of short and intermediate term contracts and spot purchases. Alternatively, PPL Energy states that suppliers should be permitted to provide customers with a diverse supply of demand response, energy efficiency and alternative energy products in addition to more traditional supply sources. FES endorses the ''case by case'' approach.

 OCA does not advocate for a specific ''prudent mix,'' preferring a flexible approach that varies between DSPs and market conditions.

 RESA notes that a ''prudent mix'' of contracts is that which will result in a competitive, sustainable retail market, ensures customers of the least cost over time and should result in a plan that produces market reflective and market responsive rates reflecting all of the relevant costs incurred by the EDC to provide default service. RESA cautions against a ''one size fits all'' approach to the ''prudent mix'' standard recognizing that the transition to a fully competitive end-state will result in a varying mix of contracts depending on where the market segment is in the transition process. RESA advocates for an end-state that relies on short term contracts and spot purchases and less on long term contracts. RESA notes that over-reliance on long term contracts runs the risk of customers being forced to pay higher ''out of date'' rates during a period of declining prices. RESA firmly opposes the use of long term contracts.

 ICG maintains the position that, at a minimum, two types of products must be included to constitute a mix. Providing only hourly priced service does not result in a ''prudent mix'' of spot, long-term and short-term contracts for the large commercial and industrial customers. FES opposes this suggestion in its Reply Comments.

 CP advances the notion that the language of Act 129 requiring a prudent mix of spot market purchases, short-term contracts and long-term contracts means that all three types of purchases must be part of each and every procurement type.

 In Reply Comments, Citizens/Wellsboro takes issue with RESA's market reflective/market responsive proposal terming it a restatement of the prevailing market price procurement standard that Act 129 eliminated.

 PECO disagrees in response to suggestions that a ''prudent mix'' must include some minimum combination of spot price, short-term and long-term contracts. Adoption of minimum procurement provisions reduces the flexibility of DSPs to develop procurement plans that reflect different DSP and customer characteristics and evolving wholesale and retail markets. Minimum procurement requirements are best considered as part of individual default service plan evaluations.

 In evaluating this question, we are guided by the language of Section 2807(e) (3.2) of the Public Utility Code which states that electric power procured pursuant to a default service plan shall include a prudent mix of the following: spot market purchases, short-term contracts and long-term contracts entered into as a result of an auction, RFP or bilateral contract. There is no guidance given regarding what constitutes the composition of a ''prudent mix.''

 On this point, there was substantial agreement that the term ''prudent mix'' be interpreted in a flexible fashion. RESA states that a ''prudent mix'' should be that combination of contracts that will result in a competitive, sustainable retail market that assures default service customers of generation service at the least cost over time. PECO makes the point that ''prudent mix'' be linked to ''least cost'' and take into account price stability. PPL and PECO both recommend that the DSP have the discretion to propose a mix of contracts that are appropriate based on customer characteristics. Most of the generators advocate for a ''case by case'' determination. Some generators recommend a diverse supply of demand response, energy efficiency and alternative energy products. OCA prefers an approach to developing a ''prudent mix'' that allows for variation between DSPs.

 We agree with the majority of parties that the ''prudent mix'' of contracts be interpreted in a flexible fashion which allows the DSPs to design their own combination of products that meets the various obligations to achieve ''least cost to customers over time,'' ensure price stability, and maintain adequate and reliable service. As we have done on other aspects of the plan review process, we will continue to review each plan on a ''case by case'' basis that independently evaluates the merits of each default service plan where input from stakeholders is assured. We reaffirm our commitment that a ''prudent mix'' include a combination of spot purchases, short, intermediate and long-term contracts recognizing the limitation of 25% on long-term contracts under Section 2807(e)(3.2)(iii).

 We do reject the positions of those parties that ''prudent mix'' be defined to always require a specific mix or percentage of types of contract components in each default service plan or a minimum of two types of products. We also reject the position of RESA that long term contracts should not be part of the ''prudent mix'' standard. Our concern with adopting specific parameters is that adoption of specific component requirements creates constraints that limit the flexibility of the DSP to design a combination of products that meets the requirements under the Competition Act and Act 129.

 7. Does a ''prudent mix'' mean that the contracts are diversified and accumulated over time?

 To a degree, this question overlaps with Question 6 and the responses also repeated in large measure parties' response to Question 6. The purpose of this question was to delve more deeply into the benefits of diversification and accumulation of contracts in meeting default service procurement requirements. The majority of responding parties were generally in favor of interpreting the ''prudent mix'' as including diversification and accumulation of contracts that incorporates such concepts as laddering and dollar cost averaging.

 Among the EDCs, PPL states that a ''prudent mix'' is established through the procurement process that involves four solicitations a year. The ''prudent mix'' can change over time due to changing market conditions but the term does not mean that contracts must be diversified and accumulated over time. Allegheny employs a ''dollar cost averaging'' method for procurement with its various affiliates. In this manner, Allegheny can mitigate extraordinary market events and assure its customers consistent value. Duquesne points out that having more contracts does not always mean less risk and staggering contracts may not always be warranted when a fixed price full requirements contract represents less risk for customers.

 PECO makes the important point that ''diversity'' of contracts should not be confused with a ''prudent mix'' where full requirements contracts can include significant mitigation risks for customers by ensuring fixed prices regardless of congestion costs, usage patterns, weather and other factors.

 The generators (Exelon, PPL, Constellation) generally support the proposition that procurement plans can potentially be achieved by contracts that are diversified and accumulated over time. Utilizing a laddering approach with varying procurement periods and different contract durations can benefit customers through cost averaging. Where a portfolio of FR contracts are laddered, customers are insulated from market price volatility that may occur where supply contracts are all purchased at one time.

 RESA supports diversified contracts accumulated over time as long as the contracts are short-term. RESA states that laddering long-term contracts does not make the default service rate market reflective because they will not reflect the true market price of electricity.

 Certain parties recommended specific restrictions on the number and types of products offered. Citizens/ Wellsboro and ICG recommend offering at least two products. Allegheny states that only spot purchases are appropriate for industrial customers.

 OCA generally supports diversification of supply contracts as part of a portfolio approach both in timing of purchases and in terms of products procured.

 OSBA cautions that the Commission should retain its current practice of requiring DSPs to conduct multiple procurements. The Commission should not mandate the timing of procurements or the mix of products.

 OCA, in its Reply Comments, opposes proposals by Citizens/Wellsboro, ICG and Allegheny that seek to impose certain restrictions on the types of products offered.

 The tenor of the comments received on this question affirm our prior understanding that, on balance, accumulation and diversification of contracts is a beneficial practice for DSPs to engage in when developing their procurement plans. We agree with those parties that utilizing such practices as laddering contracts, with varying procurement periods and contract durations over multiple procurements provide definite benefits in terms of minimizing the impacts of market volatility and decreasing customer risk.

 Therefore, we continue to endorse the use of contract diversification and accumulation as part of the default supply procurement process, but leave it to the DSPs to develop those methods of accumulation and diversification that best meet the needs and characteristics of the customer base and service territory. Our review of the individual default service plans will provide an opportunity for interested parties to critique shortcomings in the methods employed by individual DSPs. We reject the recommendations of those parties such as RESA, ICG and Citizens/Wellsboro that seek to set limits on the numbers and types of products that should be included as part of the procurement portfolio.

 8. Should there be qualified parameters on the ''prudent mix''? For instance, should the regulations preclude a DSP from entering into all of its long-term contracts in one year?

 On this point, EDCs generally opposed specific parameters on what constitutes a ''prudent mix'' recommending instead a ''case by case'' evaluation of each plan as it is filed. The EDCs generally recommend that the Commission should retain flexibility in its regulatory review process by not prescribing restrictive parameters.

 Among the generators, Exelon and Constellation prefer maintaining the present plan review process that provides maximum flexibility and rejects the establishment of specific parameters. PPL Energy recommends implementing regulations that restrict DSPs from entering into contract types all in one year although it recognizes that there may be situations where entry into contracts in one year may be appropriate.

 The OCA likewise recommends against implementing an overly restrictive set of parameters for product mix achieved by each DSP, recognizing that DSPs should be expected to incorporate ''best practices'' to ensure diversity of supply and limit over-reliance on any one product.

 OSBA recommends deferral of any decision until the Commission has more opportunity to analyze the results of current default service plans.

 As with our response to Question 7, the majority of comments recommend against setting firm qualified parameters on what constitutes a ''prudent mix'' insofar as setting requirements reduces the flexibility of the DSP to design a procurement plan that best suits the requirements and characteristics of the customer base and the service area.

 We agree with those parties that setting specific requirements unduly reduces flexibility of the DSP to achieve a ''prudent mix'' that meets the ''least cost over time'' standard while ensuring rate stability and adequate and reliable service. We will leave to the DSP the appropriate design of the procurement process recognizing that we reserve the discretion to review and approve the DSP's plan when it is filed. We do not at this time see the need to implement regulations restricting a DSP from entering into all of its long-term contracts in one year.

 9. Should the DSP be restricted to entering into a certain percentage of contracts per year?

 On this question, the parties' responses were largely dictated by their response to Question 8. EDCs opposed any restrictions on DSPs entering into a certain percentage of contracts per year expressing a preference for a ''case by case'' review of each procurement plan. Generators opposed any restriction, recommending the more flexible regulatory approach of evaluating each case on its own merits recognizing that there is a multiplicity of procurement plans.

 OCA also opposes this requirement and cautions against approving a plan that has too many contracts expiring in one year. OSBA recommends deferral of any decision until the Commission has more opportunity to analyze the results of current default service plans.

 As with our discussion of Questions 8 and 9, we refrain from taking a position in favor of or recommending the establishment of fixed percentages of contracts per year as such a step would reduce the flexibility of DSPs to design procurement plans that best suit their own supply requirement and the requirements of retail customers.

 10. Should there be a requirement that, on a total plan basis, the ''prudent mix'' means that some quantity of total plan default service load must be served through spot market purchases, some quantity must be served through short-term contracts, and some quantity must be served through long-term contracts?

 As with the prior three questions, EDCs generally resisted any requirement that the definition of ''prudent mix'' means a specific quantity of spot market purchases, long-term contracts and short-term contracts. EDCs believe that a ''prudent mix'' will evolve over time and that a minimum quantity of specific electricity products should not be prescribed. PPL states that it is likely that the ''prudent mix'' will change with market conditions and can be reflected in future DSP procurement plan filings. Similarly, the generators do not endorse a specific quantity requirement for electricity products noting that the 25% limit on DSP projected load should be the limit on any fixed requirements.

 OCA does not endorse a specific requirement but urges that all three types of purchases be considered as part of the default service portfolio approach. OSBA concedes in its comments that there is no clear guidance on this issue and that the Commission has already determined there is no legal requirement there must be, as part of a default service plan, a specific quantity of load served by specific products.

 ICG opines that the prudent mix standard can vary by class as long as at least two products are offered. ICG asserts that providing only hourly priced service does not result in a ''prudent mix'' for large commercial and industrial customers.

 RESA presents a forceful analysis on why increased reliance on long-term contracts is not to be recommended for the following reasons: (1) a substantial percentage of supply will be based on prices that are substantially out of date; (2) long-term contracts deprive customers of price decreases in a time of declining prices; (3) long-term fixed price contracts impede the legislative goal of promoting retail competition; (4) there is no guarantee that long-term fixed price contracts will produce lower rates for customers; and (5) long-term contracts require suppliers to factor in higher capital costs into bid prices.

 Based on the comments received and our further consideration, we do not believe it is prudent or necessary at this time to establish specific percentages of default service load that should be served under long-term contracts, short-term contracts or spot market purchases. We do agree with OCA that all types of contract products be considered. We also find merit in the points raised by RESA against increased reliance on long-term contracts and we caution parties not to be overly wedded to long-term contracts as a major factor in their portfolio requirements. In declining to set fixed quantities for portfolio requirements, we allow DSPs maximum flexibility to design their default service plans with a minimum of restrictions while retaining our ability to review and evaluate plans on a case by case basis.

 11. Should there be a requirement that some quantity of each rate class procurement group's load be served by spot market purchases, some quantity through short-term contracts, and some quantity through long-term contracts? In contrast, should a DSP be permitted to rely on only one or two of those product categories with the choice depending on what would be the prudent mix and would yield the least cost to customers over time for that specific DSP?

 On this point, the EDCs resist imposing requirements that portions of each rate class be served by specific quantities of product. PECO and Duquesne oppose any fixed requirements. FirstEnergy and Citizens/Wellsboro indicate that a DSP should be permitted to rely on one or two product categories if necessary. Allegheny and PPL point out that a DSP should be permitted to develop plans based on the characteristics of each rate class. The generators uniformly opposed this requirement.

 RESA recommends default service plans be designed to gradually transition toward a robust and competitive end-state. ICG prefers that a prudent mix contain more than one product. OCA prefers a mix of all products for residential customers. OSBA points out that the Commission has already decided there is no legal requirement that the ''prudent mix'' for each rate class include specific quantities from each product.

 Based on the comments received and our further consideration, we do not believe it is prudent or necessary at this time to establish specific quantities of default service load that should be served under long-term contracts, short-term contracts or spot market purchases. As indicated in our responses to Questions 8 through 10, prescribing specific parameters and minimum load or product parameters limits the flexibility of the DSP to design a default service portfolio that best fits the needs of its service territory and customer base.

 12. Should the DSP be required to hedge its positions with futures including natural gas futures because of the link between prices of natural gas and the prices of electricity?

 EDCs generally opposed any requirement to hedge their positions with futures products including natural gas futures. PPL states that DSPs generally use RFPs and auctions for procurement and thus do not have to hedge nor should DSPs be required to hedge positions as there is risk associated with hedging and specialized expertise is required to perform this function in a competent manner. PECO and Citizens/Wellsboro state that DSPs should be permitted, but not required, to utilize hedges because properly structured hedges can provide protection against price changes in wholesale electricity markets. FirstEnergy opposes mandated hedging and notes that requiring the use of one market method over another is unlikely to result in the lowest cost to customers over time.

 Generators largely oppose the use of mandated hedging. PPL Energy highlights the commodity risk and lack of DSP expertise as primary reasons for not endorsing this method. Exelon notes that there may be instances when a DSP can use gas hedging options to reduce risk and in those cases should be permitted to do so.

 RESA opposes hedging as it is fraught with risk and, when it fails, customers will pay the consequences. RESA cites to prior Commission statements that it is ''generally skeptical of DSP's ability to beat the market.''

 OCA indicates that hedging products should be the types of products considered for inclusion in a portfolio if they can contribute to price stability, but these products should not be mandated. OSBA recommends the Commission defer a decision on this question.

 Based on the extent of comments received, we do not see a compelling reason to require DSPs to employ hedging strategies, either natural gas or other hedging vehicles, as part of their default service plan. As noted by the parties, DSPs do not typically have the in-house expertise to engage in these potentially risky practices that may result in additional cost to ratepayers. The use of hedging strategies does have its benefits in providing price stability in times of price volatility and we encourage DSPs to consider hedging as part of the total mix of available procurement strategies if the DSP has a level of confidence that hedging can be employed in a beneficial manner.

 13. Is the ''prudent mix'' standard a different standard for each different customer class?

 The consensus EDC response on this question was in the affirmative - that the ''prudent mix'' standard applies to all customer groups but since each customer group is different, the appropriate default service product will differ from one group to the next. PECO notes that the product mix for industrial and commercial customers will differ from the products for small commercial and residential customers, as the former classes are generally more sophisticated and have more competitive opportunities than the latter classes. Generators endorsed the ''case by case'' approach allowing for different product mixes by customer class considering the overall mandate of the default procurement process which is to achieve the least cost and greatest price stability to customers.

 OCA is generally supportive of the concept that the ''prudent mix'' standard be interpreted as allowing for customer class specific product mixes.

 OSBA also agrees with this proposition but cautions that long-term contracts will usually not be part of a ''prudent mix'' for small and medium commercial and industrial customers. Further, because medium-sized higher load factor customers (commercial and industrial) have a higher propensity to shop, long-term contracts may be imprudent for serving that group.

 The Commission notes there was substantial unanimity on this point and agrees with the parties that the ''prudent mix'' standard should be interpreted to allow for a class-specific product mix that best matches the needs of each DSP customer class. However, DSPs are advised to carefully review and update as necessary the usage characteristics of each customer class when developing class-specific product mix. We will continue to analyze DSP proposals of this nature on a ''case by case'' basis.

 14. What will be the effects of bankruptcies of wholesale suppliers and default service suppliers on the short and long-term contracts?

 We requested this information to better inform our future judgments regarding the evaluation of risk associated with supplier bankruptcy, to elicit information on the current ''best practices'' employed by DSPs and to evaluate whether additional regulations on this point are necessary.

 PPL notes that its response to supplier bankruptcies will be dictated by market conditions at the time of the bankruptcy. Both PPL and Allegheny make the point that the outcome of supplier bankruptcy will depend on whether the contract price (at time of supplier failure) is less than or more than the market price. If the former, the DSP can more easily obtain a lower-priced substitute supply. If the latter, the DSP may have to absorb the loss.

 PECO notes that the effects of bankruptcies involving long-term contracts are likely to be greater than the impacts of bankruptcy involving short-term contracts, as the duration of the load obligation of the former lasts longer and increases the degree of market uncertainty.

 FirstEnergy, PECO and other EDCs stressed the importance of establishing firm credit requirements upfront in order to minimize counterparty risk.

 Generators echo the importance of designing adequate credit protection mechanisms in supplier contracts to protect all parties against the potential for supplier failure. Constellation recommends that default supply procurement mechanisms be structured to account for all risk including, but not limited to, risks to the financial standing of the wholesale suppliers. Exelon recommends that supplier agreements require the posting of collateral equal to the difference between the contract price and the market price-collateral which can be retained for contingency procurement requirements.

 RESA endorses the inclusion of contingency provisions in the default service plan that sets forth a process to address situations where the supplier is unable to perform pursuant to the procurement contract.

 OCA and OSBA generally refer to the existing regulation requirement that specifies that default service programs include contingency plans to ensure the reliable provision of service when a wholesale supplier fails to meet its contractual obligations. OCA urges the DSP to have a contingency plan that provides for obtaining replacement supply through competitive means on the wholesale market including the possible use of the MP approach. PECO, in Reply Comments, argues against OCA's position on this point noting OCA offers no data to support its claim.

 CP suggests that, in the event of a supplier bankruptcy, the DSP be responsible for any cost differential between the contracted cost of supply and the replacement cost for the same supply. CP provides no support for the proposal. EAP, FirstEnergy and PECO vehemently oppose this suggestion terming it a contradiction of Act 129 and Section 2807(e) (3.9), as well as Commonwealth Court precedent that entitles DSPs to recovery of all costs on a full and current basis.

 We appreciate the parties' input on these important issues and commend EDCs and suppliers alike for pro-actively addressing the potential for supplier bankruptcy or other circumstances involving supplier inability to perform. Moreover, we agree with the comments of the EDCs and generators that adequate credit protection mechanisms should be a part of all supply contracts to protect customers in the event of a bankruptcy or other inability to perform. However, we do not propose to make any specific changes to either our regulations or policy statement regarding DSP credit and collateral provisions or other measures to safeguard customers in the event of supplier bankruptcy in this rulemaking. DSPs are already required to detail these credit protection mechanisms and procedures through the default service filing and review process in our regulations. In the event circumstances dictate a need to revise our regulations, we will institute an additional rulemaking to address the issue.

 We further reject CP's suggestion for holding DSPs responsible for cost differentials due to supplier failure as inconsistent with Section 2807(e)(3.9) and appellate precedent which ensures full cost recovery.

 DSPs should strive to provide as much detail as possible including sample contract language and explanations in their default service plans regarding the DSP procedures in the event of supplier bankruptcy and/or other potential scenarios involving supplier failure. We endorse RESA's proposal to include contingency provisions in the default service plan that set forth a process to address situations where wholesale suppliers are unable to perform pursuant to the procurement contract. Moreover, we believe our DSPs are capable of independently developing procedures for addressing supplier bankruptcy -procedures that are best designed to minimize impacts on ratepayers when these unfortunate events occur.

 15. Does Act 129 allow for an after-the-fact review of the ''cost reasonableness standard'' in those cases where the approved default service plan gives the EDC substantial discretion regarding when to make purchases and how much electricity to buy in each purchase?²

 EDC parties were fairly adamant in their position that Act 129 does not allow for an ''after the fact'' review of the cost reasonableness standard based on the language of Section 2703(e)(3.8) of the Competition Act that permits the Commission to conduct an ''after the fact'' review to disallow costs only for non-compliance with approved default service plans or where there is the commission of fraud, collusion or market manipulation.

 Generator parties concur in this assessment. Constellation observes that adoption of the MP as opposed to the FR approach may invite EDC market-timing practices that could necessitate ''after the fact'' regulatory and prudence review by the Commission.

 RESA and OCA also oppose an ''after the fact'' review of DSP procurement plans on the same legal grounds, with the exception of those provisions listed under Section 2807(3.8).

 OSBA favors an ''after the fact'' review where the DSP has substantial discretion in the nature and timing of default service with reference to the occurrence of conditions provided for at Section 2807(e)(3.8).

 In their Reply Comments, EAP, Citizens/Wellsboro, FirstEnergy and PECO all contest OSBA's interpretation that, under certain circumstances, ''after the fact'' review may be proper. These parties, especially PECO, do not believe that the reference to ''reasonable costs'' in Section 2807(e)(3.9) is intended to create the opportunity for general after the fact prudence review in light of the very limited exceptions to full cost recovery set forth in Section 2807(e)(3.8). PECO suggests that if the Commission grants a certain level of discretion to the DSP in the procurement review process, then there should be no second guessing of that discretion through additional cost recovery proceedings.

 We have also carefully considered the extensive comments on this question and agree with the majority of the parties who interpret the language of Act 129 as not legally permitting an ''after the fact'' review of default service plans except for the two exceptions provided for under Section 2807(3.8). These exceptions are: (i) failure to comply with the Commission-approved procurement plan, and (ii) evidence of fraud, collusion or market manipulation with respect to the contracts. We herein reject OSBA's proposed interpretation. To interpret our authority to allow ''after the fact'' review would, in our view, unduly subject DSPs to a level of second-guessing and regulatory scrutiny that is inconsistent with the purpose of both the Competition Act and Act 129. Further, this limitation on our ability to conduct ''after the fact'' reviews of a DSP procurement plan (other than under Section 2807(3.8)) puts additional responsibility on this Commission to carefully analyze, scrutinize and, where need be, challenge the DSP on the details of its procurement plan.

 However, by not exercising after the fact review, we are not giving the DSPs unfettered discretion in the design of their default service plans. We encourage the DSPs to clearly articulate in their filings reasonable parameters and constraints applicable to their supply acquisition schedules and hedging mechanisms.

 16. How should the requirement that ''this section shall apply'' to the purchase of AECs be implemented. Section 2807(e)(3.5) states that ''. . . the provisions of this section shall apply to any type of energy purchased by a default service provider to provide electric generation supply service, including energy or alternative energy portfolio standards credits required to be purchased, etc.''

 On this question, the EDCs' general position is that the requirements for the purchase of AECs should be identical to and treated no differently than any other component of the total power supply. FirstEnergy, Duquesne and PPL contend that there is no single correct way to procure AECs—bilateral agreements, auctions, RFPs as well as long-term, short-term and spot purchases are all includable and essential components of default service supply. Allegheny advocates for spreading the renewable obligation across many winning bidders as a means of inviting competition and creating diversity of supply for renewable resources.

 PECO provided the most detailed response to the question from the EDC perspective:

1. Section 2807(e)(5) provides that Section 2807(e) ''shall apply'' to the procurement of any type of energy by a DSP for electric generation service, including energy or AECs required to satisfy the requirements of the AEPS.

2. This provision is intended to ensure that the framework of competitive procurement established by Act 129 is also applied to the purchase of AECs. DSPs should acquire AECs through auctions and RFPs and should be in accordance with a Commission-approved plan.

3. AECs should also be procured through a ''prudent mix'' of contracts designed to ensure ''least cost over time'' but there is no requirement that the AEC component of a ''prudent mix'' address adequacy and reliability since those generation service-related obligations are not related to AEC compliance obligations.

4. Establishing ''least cost'' for AEC procurements should take into account the benefits of price stability for customers since wide variations in AEC pricing could have significant effects on retail rates.

5. Procurement of all AECs through short-term and spot purchases should be avoided as should undue reliance on only long-term contracts due to the negative price characteristics associated with over reliance on these resources.

6. Given the developing nature of the AEC markets, the Commission should permit a variety of procurement plans for AEPS compliance. DSPs should be able to obtain AECs from full requirements suppliers as well as enter into long- term, short-term and spot purchases to address shortfalls at the end of the AEPS compliance year.

7. The Commission should interpret Section 2807(e)(3.5) flexibly to both facilitate AEPS compliance and help ensure ''least cost'' to customers for AECs.

(PECO Comments, pp. 19-20).

 Allegheny states that renewable obligations are included as part of the full-requirement RFP process and are included in the purchased product from the wholesale market. Allegheny advocates for spreading the renewable obligation across many winning bidders, thus inviting competition and creating the opportunity for diversity of supply of renewable resources resulting in lower renewable pricing for the benefit of customers. For the spot market load served by the EDC, each EDC should be allowed to present plans to the Commission that allow for the procurement of renewable credits through a separate RFP process layering in competitively bid purchase contracts over time to serve the expected load and then transacting in the spot market to balance the load as necessary.

 PPL states that the Commission regulations should explicitly address that AECs are to be considered part of default supply.

 Exelon emphasizes that the DSP should have flexibility in how it proposes to secure required AECs and that the language of the statue clearly states that simply because AECs are required to be purchased pursuant to the AEPS does not exclude these energy products from the over-arching goals of Act 129 to achieve least cost and price stability for default service customers. Constellation states that each EDC must account in its default service plan for how it will meet the requirements of the AEPS. One way of meeting this obligation is to include the AEC requirement within the obligations placed on a wholesale FR product supplier.

 RESA makes the important point that this Commission recommended, in its Act 129 Proposed Rulemaking Order at p. 25, that DSPs should utilize long-term contracts to meet their requirements under the AEPS. However, RESA also recommends that DSPs' utilization of long-term contracts for procurement of AECs fulfills the requirement of utilizing long-term contracts under Act 129. RESA further suggests that EDCs be permitted to procure long-term renewable contracts while assigning the AECs to all load serving entities on a load ration share basis and recover the costs of long-term procurements through non-bypassable charges. RESA contends this approach takes the long- term contract out of the default service price and puts EGSs on the same footing as EDCs.

 OCA briefly indicates that, in its view, the DSP must actively engage the market for AECs in the same manner as it would procure other sources of default service supply.

 OSBA observes that the prudent way to conduct competitive procurement of AECs will vary between DSPs and between rate class procurement groups. OSBA suggests that the acquisition of AECs be included as part of the full requirements contracts serving the default service loads of small business customers.

 PECO, in Reply Comments, states that it would be appropriate, in light of the developing alternative energy market, to apply Section 2807(e) (5) on a case by case basis instead of creating specific regulatory requirements at this time.

 Of the many comments received, we are inclined to adopt PECO's detailed recommendations as the best statement of our position on this issue. We generally agree with PECO that the ''shall apply'' provision of Section 2807(e)(5) should be interpreted to ensure that the framework of competitive procurement established by Act 129 is also applied to the purchase of AECs. In so doing, it is appropriate for DSPs to acquire AECs through a variety of methods, including FR purchases, as well as long-term, short-term and spot purchases. We adopt the recommendations of those parties that advocate allowing EDCs to present plans to the Commission that allow for procurement of renewable credits through separate RFPs that layer in competitively bid purchase contracts over time and then purchasing from the spot market to balance the load. We do not believe that undue reliance on a particular product is advisable given the relatively recent development of the AEC market and the pricing of certain renewable products such as solar, which may not reflect the market price of power. Finally, the Commission continues to support flexibility to permit DSPs to acquire needed renewable AECs in a manner that facilitates compliance with both the Competition Act and Act 129.

 RESA suggests that a DSP can fulfill any requirement for incorporating a long-term contract requirement into a default service plan through long-term contracts for its Act 129 requirements. We do not agree with this interpretation, which would effectively limit the use of long-term contracts to procurement of renewable requirements. As we have stated throughout this Order, we are adopting a position that maximizes a DSP's flexibility to meet its default supply requirement, the ''prudent mix'' obligation and the ''least cost to customers over time'' mandate by not limiting the degree to which the DSP utilizes whatever component it chooses to achieve the ''prudent mix'' standard.

 Finally, we decline to recommend adopting any further regulations in this areas until we have sufficient experience with the developing market in renewable resources and reserve the right to address this area in future rulemaking proceedings.

 In summary, we are adopting these final-form regulations in order to implement the Act 129 changes to the statutory standards for the acquisition of electric generation supply by EDCs for their default service customers, including: requirements in regard to competitive procurement, a prudent mix of contract types, least cost to customers over time, and adequate and reliable service.

Regulatory Review

 Under section 5(a) of the Regulatory Review Act (71 P. S. § 745.5(a)), on April 15, 2010, the Commission submitted a copy of the notice of proposed rulemaking, published at 40 Pa.B. 2267 (May 1, 2010), to IRRC and the Chairpersons of the House Committee on Consumer Affairs and the Senate Committee on Consumer Protection and Professional Licensure for review and comment.

 Under section 5(c) of the Regulatory Review Act, IRRC and the House and Senate Committees were provided with copies of the comments received during the public comment period, as well as other documents when requested. In preparing the final-form rulemaking, the Commission has considered all comments from IRRC, the House and Senate Committees and the public.

 Under section 5.1(j.2) of the Regulatory Review Act (71 P. S. § 745.5a(j.2)), on March 14, 2012, the final-form rulemaking was deemed approved by the House and Senate Committees. IRRC met on March 15, 2012, and disapproved the final-form rulemaking. Under section 5.1(e) of the Regulatory Review Act, IRRC met on May 17, 2012, and approved the final-form rulemaking.

Conclusion

 Accordingly, under Sections 501, 1301, 1501 and 2807 of the Public Utility Code, 66 Pa.C.S. §§ 501,1301, 1501 and 2807; Sections 201 and 202 of the Act of July 31, 1968, P. L. 769 No. 240, 45 P. S. §§ 1201—1202 and the regulations promulgated at 1 Pa. Code §§ 7.1, 7.2 and 7.5; Section 204(b) of the Commonwealth Attorneys Act, 71 P. S. § 745.5 and Section 612 of The Administrative Code of 1929, 71 P. S. § 732 and the regulations promulgated thereunder at 4 Pa. Code §§ 7.231—7.324, we are considering adopting the proposed regulations set forth in Annex A; Therefore,

It Is Ordered That:

 1. The regulations of the Commission, 52 Pa. Code Chapter 54, are amended by amending §§ 54.181, 54.182 and 54.184—54.188 to read as set forth in Annex A.

 (Editor's Note: Section 54.181 was not included in the proposed rulemaking published at 40 Pa.B. 2267.)

 2. The Secretary shall submit this order and Annex A to the Governor's Budget Office for review of fiscal impact.

 3. The Secretary shall submit the order and Annex A to the Office of Attorney General for approval as to legality.

 4. The Secretary shall certify this order and Annex A and deposit them with the Legislative Reference Bureau for publication in the Pennsylvania Bulletin.

 5. This final rulemaking shall become effective upon publication in the Pennsylvania Bulletin.

 6. The Secretary shall submit this order and Annex A for review by the designated standing committees of the General Assembly, and for review and approval by IRRC.

 7. A copy of this order and Annex A shall be filed at Doc. No. M-2009-2140580 and Doc. No. L-2009-2095604 and be served upon all parties of record and statutory advocates.

 8. The contact person for this matter is James P. Melia, Assistant Counsel, Law Bureau, (717) 787-1859.

ROSEMARY CHIAVETTA, 
Secretary

 (Editor's Note: For the text of the order of the Independent Regulatory Review Commission relating to this document, see 42 Pa.B. 3182 (June 2, 2012).)

 Fiscal Note: Fiscal Note 57-273 remains valid for the final adoption of the subject regulations.

Statement of Commissioner Pamela A Witmer

 Prior to joining my staff, Shelby Linton-Keddie was employed by a law firm that served as counsel to a party that submitted comments in the above-referenced proceeding. Therefore, to avoid any appearance of impropriety arising from her previous employment, I wish to note that I have not been advised by Shelby Linton-Keddie regarding this matter.

PAMELA A. WITMER, 
Commissioner

Annex A

TITLE 52. PUBLIC UTILITIES

PART I. PUBLIC UTILITY COMMISSION

Subpart C. FIXED SERVICE UTILITIES

CHAPTER 54. ELECTRICITY GENERATION CUSTOMER CHOICE

Subchapter G. DEFAULT SERVICE

§ 54.181. Purpose.

 This subchapter implements 66 Pa.C.S. § 2807(e) (relating to duties of electric distribution companies), pertaining to an EDC's obligation to serve retail customers at the conclusion of the restructuring transition period. This subchapter ensure that retail customers who do not choose an alternative EGS, or who contract for electric energy that is not delivered, have access to generation supply procured by a DSP pursuant to a Commission-approved competitive procurement plan. The EDC or other approved entity shall fully recover all reasonable costs for acting as a default service provider of electric generation supply to all retail customers in its certificated distribution territory.

§ 54.182. Definitions.

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

 Alternative energy portfolio standards—A requirement that a certain percentage of electric energy sold to retail customers in this Commonwealth by EDCs and EGSs be derived from alternative energy sources, as defined in the Alternative Energy Portfolio Standards Act (73 P. S. §§ 1648.1—1648.8).

 Bilateral contract—The term as defined in 66 Pa.C.S. § 2803 (relating to definitions).

 Commission—The Pennsylvania Public Utility Commission.

 Competitive bid solicitation process—A fair, transparent and nondiscriminatory process by which a default service provider awards contracts for electric generation supply to qualified suppliers who submit the lowest bids.

 DSP—Default service provider—The term 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 energy purchases, technical requirements and related forms and agreements.

 Default service procurement plan—The electric generation supply acquisition strategy a DSP will use in satisfying its default service obligations, including the manner of compliance with the alternative energy portfolio standards requirement.

 Default service program—A filing submitted to the Commission by a DSP that identifies a procurement plan, an implementation plan, a rate design to recover all reasonable costs and other elements identified in § 54.185 (relating to default service programs and periods of service).

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

 EDC—Electric distribution company—The term has the same meaning as defined in 66 Pa.C.S. § 2803.

 EGS—Electric generation supplier—The term has the same meaning as defined in 66 Pa.C.S. § 2803.

 FERC—The Federal Energy Regulatory Commission.

 Maximum registered peak load—The highest level of demand for a particular customer, based on the PJM Interconnection, LLC, ''Peak Load Contribution Standard,'' or its equivalent, and as may be further defined by the EDC tariff in a particular service territory.

 PTC—Price-to-compare—A line item that appears on a retail customer's monthly bill for default service. The PTC is equal to the sum of all unbundled generation and transmission related charges to a default service customer for that month of service.

 RTO—Regional transmission organization—A FERC-approved regional transmission organization.

 Retail customer or retail electric customer—These terms have the same meaning as defined in 66 Pa.C.S. § 2803.

 Spot market energy purchase—The purchase of an electric generation supply product in a FERC-approved real time or day ahead energy market.

§ 54.184. Default service provider obligations.

 (a) While an EDC collects either a competitive transition charge or an intangible transition charge or until 100% of an EDC's customers have electric choice, whichever is longer, an EDC as a default service provider shall be responsible for the reliable provision of default service to retail customers who are not receiving generation services from an alternative EGS within the certificated territory of the EDC that it serves or whose alternative EGS has failed to deliver electric energy.

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

 (c) Following the expiration of an EDC's obligation to provide electric generation supply service to retail customers at capped rates, if a customer contracts for electric generation supply service and the chosen EGS does not provide the service, or if a customer does not choose an alternative EGS, the default service provider shall provide electric generation supply service to that customer pursuant to a Commission-approved competitive procurement process that includes one or more of the following:

 (1) Auctions.

 (2) Requests for proposals.

 (3) Bilateral agreements entered into at the sole discretion of the default service provider which shall be at prices that are either of the following:

 (i) No greater than the cost of obtaining generation under comparable terms in the wholesale market, as determined by the Commission at the time of execution of the contract.

 (ii) Consistent with a Commission-approved competition procurement process. Agreements between affiliated parties, including bilateral agreements between electric utilities and affiliated generators, shall be subject to review and approval of the Commission under 66 Pa.C.S. §§ 2101—2107 (relating to relations with affiliated interests). The cost of obtaining generation from any affiliated interest may not be greater than the cost of obtaining generation under comparable terms in the wholesale market at the time of execution of the contract.

 (d) A DSP shall continue the universal service and energy conservation program in effect in the EDC's certificated service territory or implement, subject to Commission approval, similar programs consistent with 66 Pa.C.S. §§ 2801—2815 (relating to Electricity Generation Customer Choice and Competition Act) and the amendments provided under the act of October 15, 2008 (P. L. 1592, No. 129) providing for energy efficiency and conservation programs. The Commission will determine the allocation of these responsibilities between an EDC and an alternative DSP when an EDC is relieved of its DSP obligation.

§ 54.185. Default service programs and periods of service.

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

 (b) The Commission will hold hearings as necessary on the proposed plan or amended plan. If the Commission fails to issue a final order on the plan or amended plan within 9 months of the date that the plan is filed, the plan or amended plan will be deemed to be approved and the default service provider may implement the plan or amended plan as filed. Costs incurred through an approved competitive procurement plan shall be deemed to be the least cost over time.

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

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

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

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

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

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

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

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

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

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

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

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

§ 54.186. Default service procurement and implementation plans.

 (a) A DSP shall acquire electric generation supply at the least cost to customers over time for default service customers in a manner consistent with procurement and implementation plans approved by the Commission.

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

 (1) The procurement plan shall be designed so that the electric power procured under § 54.184(c) (relating to default service provider obligations) includes a prudent mix of the following:

 (i) Spot market purchases.

 (ii) Short-term contracts.

 (iii) Long-term purchase contracts, entered into as a result of auction, request for proposal or bilateral contract that is free of undue influence, duress or favoritism of greater than 4 years in length but not greater than 20 years. The default service provider shall have sole discretion to determine the source and fuel type. Long-term purchase contracts must be 25% or less of the DSP's projected default service load unless the Commission, after a hearing, determines for good cause that a greater portion of load is necessary to achieve least cost procurement.

 (A) EDCs or Commission-approved alternative suppliers may offer large customers with a peak demand of 15 megawatts or greater at one meter at a location in its service territory any negotiated rate for service at all of the customers' locations within the service territory for any duration agreed upon by the EDC or alternative supplier and the large customer.

 (B) The Commission may determine that a contract is required to be extended for longer than 20 years if the extension is necessary to ensure adequate and reliable service at least cost to customers over time.

 (2) A prudent mix of contracts shall be designed to ensure:

 (i) Adequate and reliable service.

 (ii) The least cost to customers over time.

 (iii) Compliance with the requirements of paragraph (1).

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

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

 (5) Electric generation supply shall be acquired by competitive bid solicitation processes, spot market energy purchases, short- and long-term contracts, auctions, bilateral contracts or a combination of them.

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

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

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

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

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

 (i) A bidding schedule.

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

 (iii) Bid price formats.

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

 (v) Bid submission instructions and format.

 (vi) Price-determinative bid evaluation criteria.

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

 (A) Hourly usage data.

 (B) Number of retail customers.

 (C) Capacity peak load contribution figures.

 (D) Historical monthly retention figures.

 (E) Estimated loss factors.

 (F) Customer size distribution.

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

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

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

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

 (d) The DSP may petition for modifications to the approved procurement and implementation plans when material changes in wholesale energy markets occur to ensure the acquisition of sufficient supply at the least cost to customers over time. The DSP shall monitor changes in wholesale energy markets to ensure that its procurement plan continues to reflect the incurrence of reasonable costs, consistent with 66 Pa.C.S. § 2807(e)(3.1)—(3.4) (relating to duties of electric distribution companies).

 (e) At the time the Commission evaluates the plan and prior to its approval, in determining if the DSP's plan obtains generation supply at the least cost, the Commission will consider the DSP's obligation to provide adequate and reliable service to customers and that the DSP has obtained a prudent mix of contracts to obtain least cost on a long-term, short-term and spot market basis. The Commission will make specific findings which include the following:

 (1) The DSP's plan includes prudent steps necessary to negotiate favorable generation supply contracts through a competitive procurement process.

 (2) The DSP's plan includes prudent steps necessary to obtain least cost generation supply contracts on a long-term, short-term and spot market basis.

 (3) Neither the DSP nor its affiliated interest has withheld from the market any generation supply in a manner that violates Federal law.

§ 54.187. Default service rate design and the recovery of reasonable costs.

 (a) The Commission may modify contracts or disallow costs when after a hearing the party seeking recovery of the costs of a procurement plan is found to be at fault for either of the following:

 (1) Not complying with the Commission-approved procurement plan.

 (2) The commission of fraud, collusion or market manipulation with regard to these contracts.

 (b) The costs incurred for providing default service shall be recovered on a full and current basis through a reconcilable automatic adjustment clause under 66 Pa.C.S. § 1307 (relating to sliding scale of rates; adjustments), all reasonable costs incurred under 66 Pa.C.S. § 2807(e)(3.9) (relating to duties of electric distribution companies) and a Commission-approved competitive procurement plan. The use of an automatic adjustment clause shall be subject to audit and annual review, consistent with 66 Pa.C.S. § 1307(d) and (e).

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

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

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

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

 (g) A DSP may collect interest from retail customers on the recoveries of under collection of default service costs at the legal rate of interest. Refunds to customers for over recoveries shall be made with interest, at the legal rate of interest plus 2%.

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

 (i) Default service rates may not be adjusted more frequently than on a quarterly basis for all customer classes with a maximum registered peak load up to 25 kW, to ensure the recovery of costs reasonably incurred in acquiring electricity at the least cost to customers over time. DSPs may propose alternative divisions of customers by maximum registered peak load to preserve existing customer classes.

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

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

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

§ 54.188. Commission review of default service programs and rates.

 (a) A DSP shall file a plan or amended plan for competitive procurement with the Commission and obtain Commission approval of the plan or amended plan considering the standards in 66 Pa.C.S. § 2807(e)(3.1), (3.2), (3.3) and (3.4) (relating to duties of electric distribution companies) before the competitive process is implemented. The Commission will hold hearings as necessary on the proposed plan or amended plan. A default service program will initially be referred to the Office of Administrative Law Judge for further proceedings as may be required.

 (b) If the Commission fails to issue a final order on the plan or amended plan within 9 months of the date the plan or amended plan is filed, the plan or amended plan will be deemed approved and the DSP may implement the plan or amended plan as filed. Costs incurred through an approved competitive procurement plan will be deemed to be the least cost over time as required under 66 Pa.C.S. § 2807(e)(3.4)(ii).

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

 (d) The Commission may initiate an investigation regarding implementation of the DSP's default service program and, at the conclusion of the investigation, order remedies as may be lawful and appropriate. The Commission will not deny the DSP the recovery of its reasonable costs for purchases made pursuant to an approved competitive procurement process unless the DSP concealed or misled the Commission regarding its adherence to the program, or otherwise violated the provisions of this subchapter or the code. Except as provided under the Alternative Energy Portfolio Standards Act (73 P. S. §§ 1648.1—1648.8), the Commission may not order a DSP to procure power from a specific generation supplier, from a specific generation fuel type or from new generation only. At the time the Commission evaluates the plan and prior to approval, the Commission will consider the default service provider's obligation to provide adequate and reliable service to customers and that the DSP has obtained a prudent mix of contracts to obtain least cost on a long-term, short-term and spot market basis. The Commission will make specific findings which include:

 (1) The DSP's plan includes prudent steps necessary to negotiate favorable generation supply contracts through a competitive procurement process.

 (2) The DSP's plan includes prudent steps necessary to obtain least cost generation supply contracts on a long-term, short-term and spot market basis.

 (3) Neither the DSP nor its affiliated interest has withheld from the market any generation supply in a manner that violates Federal law.

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

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

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

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

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

 (f) A DSP may not submit tariff supplements more frequently than on a quarterly basis, consistent with § 54.187(h) and (i) (relating to default service rate design and recovery of reasonable costs), to revise default service rates to ensure the recovery of costs reasonably incurred in acquiring electricity at the least cost to customers over time. The DSP shall provide written notice to the named parties identified in § 54.185(b) of the proposed rates at the time of the tariff filings. The tariff supplements shall be posted to the DSP's web site at the time they are filed with the Commission. A customer or the parties identified in § 54.185(b) may file exceptions to the default service tariffs within 20 days of the date the tariffs are filed with the Commission. The exceptions shall be limited to whether the DSP has properly implemented the procurement plan approved by the Commission and accurately calculated the rates. The DSP shall post the revised PTC for each customer class within 1 business day of its effective date to its web site to enable customers to make an informed decision about electric generation supply options.

 (g) If a customer chooses an alternative supplier and subsequently desires to return to the local distribution company for generation service, the local distribution company shall treat that customer exactly as it would any new applicant for energy service.

 (h) A DSP may, in its sole discretion, offer large customers with a peak demand of 15 megawatts or greater at one meter location in its service territory any negotiated rate for service at all of the customers' locations within the service territory for any duration agreed upon by the DSP and the customer.

 (1)  Contract rates shall be subject to Commission review to ensure all costs are borne by the parties to the contract and no one else.

 (2) If no costs related to the rates are borne by other customers, the Commission will approve the contract within 90 days of its filing at the Commission. If the Commission does not approve the contract within the 90-day period, it shall be deemed approved.

 (i) The DSP shall offer residential and small business customers a generation supply service rate that may not change more frequently than on a quarterly basis. Default service rates shall be reviewed by the Commission to ensure that the costs of providing service to each customer class are not subsidized by any other class.

[Pa.B. Doc. No. 12-1509. Filed for public inspection August 10, 2012, 9:00 a.m.]

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²  See Section 2807(e)(3.9), which provides the EDC with the right to recover ''all reasonable costs'' incurred under Section 2807 and under an approved competitive procurement plan.

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