Contract

No, the Default Service SMA is a standard document that must be executed in its current form and without modifications by each RFP Bidder as a condition of its participation in the RFP.

Yes, you are required to execute a Default Service SMA that is specific to PPL Electric’s DSP IV in order to participate in the solicitations under PPL Electric's DSP IV.  Default Service SMAs executed as part of a prior Default Service Program such as DSP III are not applicable to this Default Service Program and will not be accepted.

That is correct for any entity seeking to rely on the creditworthiness of a foreign guarantor. The executed guaranty along with the documents required under Section 6.4(d) of the Default Service SMA such as the executed legal opinion and sworn certificates must be accepted by PPL Electric first before any unsecured credit may be granted to the default service supplier based on the creditworthiness of the foreign guarantor. In support of this, RFP Bidders may, but are not required to, submit with Bidder Qualifications a draft of the documents required under Section 6.4(d) of the Default Service SMA for review.  If a draft of the documents for evaluation are submitted, the RFP Manager will provide feedback on the evaluation of these documents to the RFP Bidder when  the RFP Bidder is notified of its status as a Qualified Bidder.

As provided in Section 3.1(h), the requirement is for the Seller to be qualified as a PJM “Load Service Entity”.

PPL Electric does not currently participate in any PJM or other similar load response programs. At this time, the Company does not intend to participate in any such program.

The Delivery Point under the Default Service SMA is “PPL_Resid_AGG”, which will be indicated in the Transaction Confirmation provided to winning bidders.

PPL Electric completes load submissions to PJM which includes distribution and transmission losses (including PJM assigned 500kV losses and unaccounted for energy). PJM applies a deration factor to the load submissions for settlement purposes. (See PJM Marginal Loss Implementation Details.) Suppliers will be paid based on the de-rated load.  Hence suppliers will be paid for loads at the retail meter adjusted upward to include the distribution and transmission loss factors, recognizing that these factors vary from time to time and are reconciled and de-rated by PJM for marginal losses (that removes transmission loss associated with the PJM state estimator model).

The PV requirement is included in the Tier I requirement.

The volumes used for the Peak and Off-peak estimated energy and capacity quantities for each month during the supply period will be supplied to winning bidders in their Transaction Confirmation.

PPL Electric will notify potential bidders of the application of the FAR clause at the time of a solicitation. If any regulatory body, such as the PaPUC or FERC notify PPL Electric of the application of the FAR clause, PPL Electric will immediately communicate this to all active and future suppliers. To date, this clause has not been applied to any PPL Electric contracts.

Costs related to black start capability is a default service supplier’s responsibility and the default service supplier is responsible for any costs or credits, as defined by PJM. Additionally, please see Appendix C (“DS Supply Specification”) of the Default Service SMA, which defines the costs PPL Electric is responsible for.  All costs and credits not defined in Appendix C are the responsibility of the default service supplier.

For the Residential Group, as you have pointed out the Default Service Load is less committed energy and capacity obtained under supply from the New York Power Authority (“NYPA”) and less 50MW of Block Supply. In general terms, PPL Electric will be a load serving entity for the Residential Customer Group that, each hour, has a load of 50 MW plus the NYPA allocation for energy and ancillary service responsibility determination, and that supplies 50 MW plus the NYPA capacity allocation of RPM capacity. DS Suppliers will be responsible for the residual energy and capacity needs of the Residential Customer Group. PJM will determine ancillary service responsibilities for PPL Electric and each supplier based on their individual loads and schedules. The difference between PPL Electric's share of Default Service Load served using the blocks and a DS Supplier's share of Default Service Load is that PPL Electric's energy and capacity responsibilities are determined as fixed MW values while a DS Supplier's responsibilities are determined as a percent of Default Service Load less the fixed MW of PPL Electric’s responsibility. For Ancillaries, PJM will calculate the ancillary service requirements for PPL Electric based on the hourly energy loads for which PPL Electric is responsible and PPL Electric's scheduling. Similarly, each DS Supplier's ancillary service responsibility will be a function of that supplier's hourly load and its scheduling. For ARRs, the winning DS Supplier will accrue and assume responsibility for the ARRs associated with the load they are serving in accordance with the PJM Agreements based upon its DS Supplier Responsibility Share. Please refer to the Default Service SMA, including Appendix C that provides specific information regarding the detailed obligations of PPL Electric and the Default Service Supplier.

No, Default Service Suppliers are not responsible for AECs pertaining to the block supply, the long-term product supply or the NYPA supply.

No. The Default Service SMA currently specifies monthly settlements.

PPL Electric's Settlement Process The Company follows and implements the PJM settlement requirements for submitting and settling supplier load at PJM. PJM settlement is currently a two-step process which includes daily eSchedules and Reconciliation. PPL implements a third step in the process when necessary to resolve significant load reallocation and accounting issues. The different steps in the process are commonly known as: Settlement A is a daily back cast whereby supplier load is allocated and aggregated by supplier on an hourly basis then submitted to PJM daily. This is a combination of actual meter read data and forecast data. Settlement B or Reconciliation, occurs two months after the metered month. This is where a true-up of approved meter data is completed and a reconciliation file is submitted to PJM that adjusts the original eSchedules for any changes in the meter data that occurred since the original data was submitted in Settlement A. Settlement B is generally considered the last step in the settlement process unless something significant changes to warrant reconciling again. Settlement C is a second reconciliation and final true-up. It is sometimes required to resolve significant inaccuracies unveiled or changes in customer load values that were discovered after Settlement B was submitted. Causes for changes in data can result from different circumstances that include but are not limited to situations such as stuck meters, lost communications and bad data. Settlement C will be performed at the discretion of the EDC. The company will limit the occurrence of Settlement C. Until which time PJM offers the processing of Settlement C reconciliations, Settlement C will be performed outside of the PJM Settlement System. When PJM offers the Settlement C service, the Company will perform and submit Settlement C reconciliations to PJM by the PJM established date for the Settlement C process and PPL will no longer perform Settlement C outside of the PJM Process. Once established, PPL will follow the PJM established policy to submit Settlement C reconciliations to PJM for processing. The Company measures and retains interval hourly data for all of its metered customer accounts on a per meter basis and maintains this data in its Meter Data Management System (MDMS). As such, the Company is able to utilize this actual interval data when it is available to report load to PJM rather than depending solely on reporting using load profiles and usage factors. Load profiles and usage factors derived by our settlement system are used to determine hourly usage for unmetered accounts. The Company strives to obtain hourly interval data for every one of its interval metered accounts. However, due to electrical outages, stuck meters, bad communications, meter memory limitations and other technical and operating issues, it is not always possible to obtain a 100% capture rate for all of the interval hourly meter readings for all of the Company's customers. Where interval hourly data is not available in either Settlements A, B or C, the Company will calculate customer load using load profiles adjusted for actual weather and usage factors. Normal weather is used when actual weather is not available. Settlement A Process For Settlement A, the Company submits aggregated hourly load schedules on a daily basis for each supplier. These load schedules are submitted to PJM within the PJM deadline requirements in the form of a unilateral Retail Load Responsibility (RLR) eSchedule for EGSs and in the form or Wholesale Load Responsibility (WLR) eSchedules for Default (POLR) suppliers and FERC load. The eSchedules are considered back cast eSchedules because they are compiled and submitted the day after the metered day in order to obtain as many actual metered load values possible. PJM calculates the charges and credits associated with each eSchedule and includes these quantities on the PJM bill. The Company's MDMS retains hourly meter reads for every customer meter. Due to the technology and complexity of the system, not all meter reads are collected sufficiently far enough ahead of time to be used in the daily back cast eSchedules. For submission of the back cast eSchedules for PJM Settlement A, the Company utilizes actual meter read data where available and company's settlement system forecasts the remaining load data. The eSchedules are adjusted for average electric losses prior to submitting them to PJM, then they are adjusted for Unaccounted For Losses (UFL). UFL accounts for any remaining losses on the system not accounted for by the average losses. UFL is allocated on a load ratio share basis to all supplier accounts. PJM de-rates the eSchedules for marginal losses as calculated by the PJM State Estimator. The original eSchedule and the de-rated eSchedule are posted and available on the PJM website and available to the counterparties on a daily basis. Settlement B Process For Settlement B, the Company reconciles the most current hourly metered load data it has in its MDMS as compared to the load values submitted in Settlement A. The difference amount between Settlement A and Settlement B for each eSchedule is the adjustment submitted to PJM. PJM calculates and bills the credits and charges for Settlement B. Settlement C Process For Settlement C, the Company will consider all metered and calculated load quantities assigned to customer accounts and aggregations by supplier at a point in time several months after Settlement B is final. Load corrections and adjustments made to customer accounts after Settlement B will be considered for Settlement C. A reconciliation file will be derived to determine the final load adjustment necessary between Settlements A, B and C. Until PJM implements the Settlement C process, the Company will calculate the credits and charges for all affected parties based on PJM billing determinants. The Company will request and require each affected participant to resolve Settlement C by signing a settlement adjustment document indicting that the Settlement C financial adjustments are to be included on the PJM Bill. The Company will arrange to forward these forms to PJM for confirmation and inclusion on the PJM Bill. Once PJM implements Settlement C, reconciliation values will be sent to PJM and PJM will handle the billing adjustments. NYPA generation is treated as an import. As such, it does not affect PPL Electric's eMetered zone load. Therefore NYPA generation is accounted for as a financial transaction by PJM. NYPA generation serves only PPL Electric's POLR or Default Service customers.  PPL Electric will adjust supplier hourly load responsibility reported to PJM to reflect the fact that NYPA supply reduces POLR or Default Service load. The data will be available to suppliers via PJM e-schedule.

The AEPS Act permits EDCs and EGSs to bank AECs created in one reporting year for use in either or both of the two subsequent reporting periods. DS Suppliers are permitted to provide AECs to PPL Electric from a prior compliance period provided that the AECs provided for a compliance period are within the allowable banking period for that compliance period.

Suppliers are not responsible for Generation Deactivation Charges.  PPL Electric is responsible for all Non-market-based Transmission Services costs.  “Non-market-based Transmission Services” is a defined term in the Default Service SMA and include Network Integration Transmission Services, Transmission Enhancement Costs, Expansion Cost Recovery Costs, Non-Firm Point-to-Point Transmission Service Credits, Regional Transmission Expansion Plan, and Generation Deactivation Charges.

PPL Electric does not have a specific “Deferred Tax Adjustment” charge for which it is retaining or assigning to any DS Supplier. Any similar PJM implemented charge is the responsibility of the DS Supplier. All charges retained by PPL Electric are identified in the Supplier Master Agreement under the definition of “Non-market-based Transmission Services”. Any charge not listed in this definition is of the responsibility of the DS Supplier.

There are no material changes to the Default Service RFP and Default Service SMA documents between the April 2018 and October 2018 solicitations. We note that some documents are solicitation specific and are generally updated at the start of each solicitation:

• RFP Addendum 1: Default Service RFP Schedule
• RFP Addendum 2: Proposal Submission Web Site Instructions
• RFP Appendix 6B: Confirmation of Credit and Financial Information
• RFP Appendix 9: Binding Bid Agreement
• SMA Exhibit 2: Allocated AECs

In addition, for this October 2018 solicitation, PPL Electric has updated its contact information in the Exhibit 3 to the Default Service SMA. The Default Service SMA includes a footer at the bottom of each page that contains the date when the document was issued or when a page was updated. In addition, the standard form of the Bid Assurance Letter of Credit and standard form of the Performance Assurance Letter of Credit are provided as separate documents in word format to facilitate the issuance of these documents by your issuing bank. The executed versions of these documents must be provided on your bank’s letter head and issued by your bank. As such, no dates were included in the footer of these documents.

Information related to the Allocated AECs that are relevant to a winning bid in a particular solicitation (e.g., the April 2018 solicitation or October 2018 solicitation) can be found in the Exhibit 2 to the Default Service SMA, which is updated for that specific solicitation. This information is also included in each bidder’s Notification of Qualification package. SRECs are allocated to bidders winning tranches in the Residential Customer Group, and the SRECs per tranche allocated to each winning supplier can be found in footnote #1 of the updated Exhibit 2 to the Default Service SMA. Under the October 2018 solicitation, 480 SRECs/tranche are allocated to Suppliers serving the 12-month Residential Product from December 1, 2018 to November 30, 2019 (240 SRECs/tranche are allocated from December 1, 2018 to May 31, 2019 and 240 SRECs/tranche are allocated from June 1, 2019 to November 31, 2019). 245 SRECs/tranche are allocated to Suppliers serving the 6-month Residential Product from December 1, 2018 to May 31, 2019. No SRECs are allocated to tranches in the Small and Large C&I Customer Groups.

PPL Electric will not be making any changes to the Default Service RFP and Default Service SMA documents as they currently stand under DSP IV.

PPL Electric does not speculate about the impact of draft legislation on the Default Service Plan or supplier obligations under the plan.  If the final version of House Bill 11 or any similar proposals are enacted by the legislature and Pennsylvania Public Utility Commission, PPL Electric will review them and communicate its findings to suppliers.

This is incorrect. SRECs are allocated to winning bidders serving the Residential Customer Group. The specific quantity of SRECs allocated per tranche is found in footnote #1 of Exhibit 2 to the Default Service SMA which is updated at the beginning of each solicitation.  Please refer to Contract FAQ-22 for more information.

The delivery term of the long-term product is from June 1, 2011 through May 31, 2021. The long-term product is for 50MW and is used to serve the load of default service customers in the Residential Customer Group.  Please see section 1.1.4 of the Default Service RFP Rules for additional information.   In general terms, PPL Electric will be a load serving entity for the Residential Customer Group that, each hour, has a load of 50 MW plus the NYPA allocation for energy and ancillary service responsibility determination, and that supplies 50 MW plus the NYPA capacity allocation of RPM capacity. Full requirements suppliers will be responsible for the residual energy and capacity needs of the Residential Customer Group. PJM will determine ancillary service responsibilities for PPL Electric and each supplier based on their individual loads and schedules. The difference between PPL Electric's share of Default Service Load served using the blocks and a full requirements supplier's share of Default Service Load is that PPL Electric's energy and capacity responsibilities are determined as fixed MW values while a full requirements supplier's responsibilities are determined as a percent of Default Service Load less the fixed MW of PPL Electric responsibility.  For Ancillaries, PJM will calculate the ancillary service requirements for PPL Electric based on the hourly energy loads for which PPL Electric is responsible and PPL Electric's scheduling. Similarly, each full requirements supplier's ancillary service responsibility will be a function of that supplier's hourly load and its scheduling.

The AEPS Act requires that the Tier I and Tier II compliance requirements be based on electric energy sold to retail electric customers, not the total generation used by an EDC or EGS to meet customer demand. (see AEPS Act at 73 P.S. § 1648.3(b)). As stated in the AEPS Act, "For each reporting period, EDCs and EGSs shall acquire alternative energy credits in quantities equal to a percentage of their total retail sales of electricity to all retail electric customers for that reporting period, as measured in MWh." (See PUC Final Rulemaking Order in Docket No. L-00060180 dated September 29, 2008, Annex A, Title 52, Subpart C, Chapter 75, Subchapter D at § 75.61(b)). PPL Electric issues quarterly AEPS Reports to winning suppliers, detailing the derated and retail MWhs, by month, by contract. In this report, suppliers are able to transparently see load values, credit obligations, and a history of transfers to date.

No.

The contract for the long-term product of 50MW expires on May 31, 2021 and the NYPA contract expires on April 30, 2032. Please also see Contract-FAQ-24 for more information.

The contract for the long-term product of 50MW expires on May 31, 2021 and the NYPA contract expires on April 30, 2032. Please also see Contract-FAQ-25 for more information.

Exhibit 2 of the Default Service SMA issued at the start of a solicitation provides the binding obligation of default service supplier that are awarded tranches in that solicitation. Please also see Other-FAQ-15 for more information.

Yes, default service suppliers are responsible for the AEPS Quarterly Adjustments. The quantity outlined in Exhibit 2 of the Default Service SMA is inclusive of the prospective AEPS Quarterly Adjustments. Please also see Other-FAQ-15 for more information.

The Alternative Energy Portfolio Standard obligation are at the retail level. Please also see Contract-FAQ-25 for more information.

Yes, PPL Electric will transfer or assign to the DS Supplier Auction Revenue Rights associated with the Default Supplier Responsibility Share. As noted in Section 2.3 of the Default Service Supplier Master Agreement, all rights, liabilities and obligations associated with such ARRs will accrue and be assumed by the DS Supplier through the transfer or assignment from PPL Electric to the DS Supplier including the responsibility and ability of the DS Supplier to request or nominate such ARRs when applicable and feasible.  Should the conditions above not be met, the entity recognized by PJM as having the right to make the nominations will nominate such ARRs for the upcoming PJM planning period and such ARRs will be allocated to the DS Supplier in accordance with the PJM Agreements based upon its DS Supplier Responsibility Share.  Please also see Other-FAQ-3 for information.

If you are a previous winner that has an existing DSP IV SMA with PPL Electric, the PDF scan of the fully executed Transaction Confirmation is all that will be required for any additional tranches won in this solicitation.

There is no requirement for a single Officer to sign all of the documents in the RFP process.  Several different Officers of the RFP Bidder may sign different documents in the RFP process.

Yes, an electronic scan of the fully executed Transaction Confirmation is all that is required and a hardcopy is not required to be mailed to PPL Electric.

At this time, use of (i) a manually signed signature or (ii) a digital signature via DocuSign or Adobe Sign is deemed automatically approved by PPL Electric, and no request is required to be made. If you will be using another form of electronic signature, please alert the RFP Manager at PPL-Procurement@nera.com by at least 2 business days prior to the Bid Proposal Due Date.

The execution of Addendum 1 to the SMA is optional. All DS Suppliers who intend to provide a manually signed signature with a second individual providing the attestation need not provide Addendum 1 to the SMA. Notwithstanding, all suppliers may provide a signed Addendum 1 to the SMA in this solicitation so that the flexibility afforded by the SMA Addendum would be applicable to all future solicitations as well.

Yes, the same Officer may sign both Addendum 1 to the SMA and the Transaction Confirmation. Please also see Contract FAQ-34.

As defined in the Default Service Supplier Master Agreement, all ARRs are assigned to wholesale suppliers. PPL Electric does not have nomination rights to the ARRs awarded to wholesale suppliers, nor does PPL have access to view the paths chosen by the suppliers that selected them.  Suppliers providing load through PPL Electric contracts are provided ARRs by PJM in association with their load share based upon these contracts. If a supplier ceases to supply a portion or all load at any point in time during the PJM planning year (June 1 through May 31), the ARRs are reassigned to the supplier(s) that take over that load. Per PJM rules, assignment of ARRs can only be zero or positive in value; therefore, no supplier assigned ARRs following any auction should be harmed as a result of some other party’s elections.

As long as an Officer of the RFP Bidder signs Addendum 1 to the Default Service SMA and the Transaction Confirmation is executed using an approved electronic signature, then the requirement for Attestation and Witness is waived as provided in Addendum 1 to the Default Service SMA. Please also see Contract FAQ-36 and Contract FAQ-38.

Please see Contract-FAQ-32, Contract-FAQ-39 and Other-FAQ-3. PPL Electric does not bid ARRs into the PJM ARR/FTR market, instead allocating ARRs to wholesale suppliers who provide default service load under the PPL Electric Default Service Plans. PPL Electric does not get involved in the supplier ARR nomination process. As such, PPL Electric does not have any information on the paths that are chosen by each suppliers during the ARR nomination process. The entities that have the opportunity to nominate paths in this process are those that are supplying default service when the ARR nomination process occurs. ARRs have been allocated to each default service supplier based on the tranches associated with such supplier pursuant to those previously executed default service SMAs. PJM provides and implements the rules associated with ARRs and FTRs, as found on their website.

PPL Electric is interpreting that the “transitional product” referenced in your question pertains to the PPL Electric Default Service Plans. These are the overarching plans that define the rules and requirements of the default service energy plans. The currently effective PPL Electric Default Service Energy Plan IV (“DSP IV”) is in effect through May 31, 2021, with some overlapping 12-month supply contracts extending through November 30, 2021. The next default service energy plan – DSP V – is currently pending before the Pennsylvania Public Utility Commission (“PA PUC”).  If approved by the PA PUC, DSP V contracts will begin on June 1, 2021. DSP V contracts run from June 1, 2021 through May 31, 2025.

The PPL Electric DSP IV program does not contain 24-month supply products for any customer group. DSP IV includes 6 and 12-month fixed price full requirements Residential and Small C&I supply contracts, and 12-month spot market full requirements Large C&I supply contracts. PPL Electric does not procure 100% of supply for Residential and Small C&I customer groups – instead implementing a laddered procurement approach, such that 12-month energy contracts overlap with each other. At the conclusion of DSP IV, those 12-month contracts procured in the final solicitation will extend into the first 6-months of the next energy plan – DSP V. As such, DSP IV and DSP V overlap to provide a transition between plans. Please also see Contract-FAQ-33 for more information.

Please see Contract-FAQ-27. Additionally, it should be noted that additional block supply contracts, or other similar contracts, may be updated in subsequent PPL Electric default service energy plans, subject to the approval of the PA Public Utility Commission. Any such updating products and services will be communicated in future energy solicitations, as appropriate.

Winning bidders are responsible for the AEPS terms and obligations as set forth in the Default Service Supplier Master Agreement, Appendix D and the Transaction Confirmations, Exhibit 2.  Any change in AEPS percent obligation made by the State after an RFP solicitation is complete will not impact the AEPS obligations set forth in Exhibit 2 for prior winning bidders. Other terms and conditions that are changed are subject to the provisions set forth in Appendix D and the details of the terms set forth by the State.  Please also see Other-FAQ-12.