First, please note that as a requirement of bidder qualification, each prospective supplier must show that it or its guarantor is rated. As stated in section 4.1.1 of the RFP Rules, “An applicant is qualified to bid in a given solicitation if, by the Cure Deficiency Deadline of that solicitation, it satisfactorily completes or updates the following: … … 3) demonstrates that its, or its guarantor's, unsecured senior long-term debt rating (or issuer rating, if the unsecured senior long-term debt rating is unavailable) is currently available from Standard & Poor's, Fitch Ratings or Moody's Investor Services.”

If an entity is not rated, but is relying on the credit and financial standing of a guarantor that is rated, then PPL Electric will extend an unsecured credit based on the Guarantor’s credit rating and tangible net worth. During the term of the SMA, PPL Electric may require additional margin if the amount of the Guaranty posted is insufficient. Please consult Article 12 of the AEC SMA and Article 14 of the Full Requirements SMA and Block SMA for more details.

Winning Bidders will be informed if their bids are recommended to the Pennsylvania Utility Commission (“PUC”) as winning bids by close of business on the Bid Proposal Due Date. The PUC will make its decision about the bid results no later than two business days after the Bid Proposal Due Date. If the bid results are approved by the PUC, PPL Electric will provide to bidders a partially executed transaction confirmation on the same business day. Bidders will have until 2 pm on the next business day to fully execute the transaction confirmation.

However, there is no specific date by which a Seller must submit an executed Unconditional Guaranty.  A winning bidder who relied on the creditworthiness of a guarantor for the purpose of Bidder Qualifications will not be granted any Unsecured Credit until it submits an Unconditional Guaranty. Under the terms of the SMA, the Supplier may provide, in lieu of an Unconditional Guaranty, another instrument of security acceptable to PPL Electric, namely a Performance Assurance Letter of Credit or cash.

It is not possible to leave the Bid Assurance Letter of Credit in place during that period as the terms of conditions of the Bid Assurance Letter of Credit are different from the terms and conditions of the Performance Assurance Letter of Credit. The two Letters of Credit have different purposes.

On a Transaction Date, the buyer’s exposure for that transaction is deemed to be zero. If, subsequent to the Transaction Date, the aggregate buyer’s exposure exceeds its amount of unsecured credit, PPL Electric will request that seller to post performance assurance. If PPL Electric requests for performance assurance before 1:00 p.m. EPT on a business day, then Seller will have one business day to provide the performance assurance in the form of cash, or two business days to provide the performance assurance in the form of a Performance Assurance Letter of Credit. The Seller has an additional business day to provide the performance assurance collateral if PPL Electric’s request is made after 1:00 p.m. EPT.

What regulatory approvals will be required for Assignment of an executed Supply Master Agreement from one Seller to another?

Unfortunately that is not possible. Should you be a winning bidder in any of the PPL Electric’s Default Service Procurement Plan (“DSPP”) RFPs, you will be required to provide a new Unconditional Guaranty to replace the current Unconditional Guaranty held by PPL Electric pursuant to the POLR SMA under PPL Electric’s Competitive Bridge Plan ("CBP"). The terms and conditions of the Unconditional Guaranty under the POLR SMA are different from the terms and conditions of the Unconditional Guaranties under PPL Electric’s DSPP SMAs. Each of the Unconditional Guaranties pursuant to SMAs under PPL Electric’s DSPP is intended to be an all-inclusive Guaranty for all SMAs for default service and alternative energy credits, which includes the POLR SMA under the CBP. The Guaranty pursuant to the POLR SMA under the CBP is not intended to be an all-inclusive Guaranty.

For additional information on this topic, please refer to DSPP FAQ 5 under Contract/General by clicking here.

No. The Full Requirements and Block SMAs currently specify monthly settlements, and PPL Electric does not envision changes to the SMAs at this time. This may be considered for the next default service proceeding for supply contracts that begin on or after June 2013.  

The file “Redline_POLR_SMA_vs_FR_SMA_071709.doc” contains redline changes that reflect differences between the POLR SMA (revised February 12, 2008) under PPL Electric's Competitive Bridge Plan and the Default Service (Full Requirements) SMA (dated July 1, 2009) under PPL Electric's Default Service Procurement Plan. This file is available here.

The file “Redline_POLR_SMA_vs_Block_SMA_071709.doc” contains redline changes that reflect differences between the POLR SMA (revised February 12, 2008) under PPL Electric's Competitive Bridge Plan and the Default Service Block SMA (dated July 1, 2009) under PPL Electric's Default Service Procurement Plan. This file is available here.

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 or Default Service load.

The data will be available to suppliers via PJM e-schedule.

Load profiles for 2011 and beyond have not yet been developed and can not yet be developed as they will depend in part upon customer consumption patterns between now and 2011. PPL Electric updates load profiles annually. PPL Electric does not generally publish load profile data. However, PPL Electric has provided hourly loads by Customer Group that reflect the application of then current load profiles to actual weather and customer usage data and these provide more information regarding hourly loads for settlement purposes than do load profiles.

For 2011 the existing settlement system will be rebuilt. The following methodology explanation applies to the 2011 settlement (Default Service Procurement Plan), which will be different than the pre-2011 system. This explanation below is the best description we can give at this time - it is how we expect the 2011 settlement system to work. It is written in the present tense even though the system is not yet in place.

Daily Back-Cast Settlement (Settlement A):

Each day the system will produce a back cast of hourly settlement loads for the prior day. These will be the basis for PJM’s initial settlement. PPL Electric’s settlement system uses actual interval load readings where available and estimates interval load values for missing data and adjusts for system loses to maintain its PPL zonal load responsibility at PJM. Included in this zone are the FERC (wholesale) account load (municipals, coops etc.), Electric Generation Supplier (EGS) load and Default Service (DS) Load. NYPA generation does not off-set the physical load since it is handled financially.

PPL Electric’s Customer Service System (CSS) marks each customer account by which supplier will supply them whether they are supplied by a FERC, EGS or DS supplier. PPL Electric’s settlement system synchronizes with CSS nightly to obtain the daily account assignments.

Once synchronized, and after the download of actual interval meter data from the meter data management system into the settlement system is complete, the remaining accounts whose actual meter read data was missing, are filled in using the combination of monthly usage factors and the appropriately assigned class load profile. The usage factors are calculated by the settlement system using the most recent 30 day usage and if that is not available, it uses the last available 30 day usage factor. Load profiles are adjusted according to actual daily weather.

The class load profiles are multiplied by the usage factors that result in the interval hourly estimates for the missing data.

After all interval loads are filled in for all accounts, the settlement analyst runs a load aggregation that breaks down the hourly loads by supplier and for further DS Load allocation. At this point, the DS Load is aggregated based on rate schedule type Residential, Small C&I and Large C&I. The hourly loads are further reallocated by the Settlement system into the following categories:

Residential:
Fixed Block (a fixed 300 MW per interval after PJM marginal loss de-ration)
Remaining 90% Load Following
Remaining 10% Real Time Priced Load Following

Small C&I:
90% Load Following
10% Real Time Priced Load Following

Large C&I
Load Following Flat Rate (for customers who chose that option)
Load Following Real Time Priced

After DS load is broken down into its categories, it is further broken town by supplier and bid transaction based on tranche bid percentage.

After the final allocation is made to DS load, average losses are added to all suppliers based on rate schedule loss assignment to the aggregated loads. (Note, however, that the block load will be a fixed 300 MW and will not be assigned losses).

For each hour, a comparison is made of the total load calculated by the settlement system to the official PJM eMeter zone value for the PPL zone. The difference is the unaccounted for losses (UFL) due to inaccuracies in estimating load and use of average rather than actual losses. The UFL is allocated across the pre eSchedules on a load ratio share basis to all suppliers. (Note, however, that as the block load is fixed it will not be assigned UFL.

At this point, the total of all final eSchedules now totals PPL’s zonal eMeter responsibility and are ready to send to PJM.

The settlement analyst reviews the eSchedules for expected results, approves and sends them to PJM to be entered in the PJM eSuites eSchedule system. PPL Electric will then read back the eSchedule values sent to PJM and verify that the values sent down are in fact correct.

Counterparty suppliers to the eSchedule contracts will be able to access this data after the eSchedules have been submitted. PPL Electric will submit eSchedules by the PJM required deadlines. PJM will apply marginal loss de-ration factors to supplier loads.

Reconciliation (Settlement B)
Reconciliation is performed exactly like the daily back-cast except that it occurs weeks after the fact, so more actual meter data is used. Because of the time delay in performing reconciliation, PPL Electric will have been able to update its meter data to include the most recent available actual data and will have corrected any bad data by the time reconciliation is performed. Once the settlement calculations have been run again with the updated values, a difference calculation is completed between the original back-cast and the reconciliation values. This difference file is called the reconciliation file and is submitted to PJM two months after the original metered month.

Settlement C
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. PPL Electric 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, PPL Electric 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 Electric will follow the PJM established policy to submit Settlement C reconciliations to PJM for processing.

For Settlement C, PPL Electric 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, PPL Electric will calculate the credits and charges for all affected parties based on PJM billing determinants. PPL Electric 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. PPL Electric 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.

How is the block product netted out of the Full Requirements load?

No. The AEPS obligations of winning suppliers in the AEC RFP will be specified in the Transaction Confirmation, and the AEPS obligations of winning suppliers in the Full Requirements RFP will be specified in Exhibit B to the Full Requirements SMA. These documents will be provided to the winning suppliers on the day the Pennsylvania Utility Commission approves the bid results of a solicitation. Thereafter, these documents will be the binding obligation of the winning suppliers, which will not change.

No. The Full Requirements and Block SMAs currently specify monthly settlements, and PPL Electric does not envision changes to the SMAs at this time. This may be considered for the next default service proceeding for supply contracts that begin on or after June 2013.

As stated in the Full Requirements SMA, the supplier is responsible for all congestion costs. PPL Electric will not be allocating any ARRs to suppliers, but suppliers will be able to independently participate in the FTR Auctions held by PJM.

It is a theoretical possibility. However, we would draw your attention to certain facts.

First, the 300 MW of block energy supply as well as the unit entitlement supply of up to 50 MW is only applicable to the Residential Customer Group.

Second, while the 300 MW of block energy pursuant to the Block Supply RFP will begin on January 1, 2011, supply from the unit entitlement product is expected to begin only on June 1, 2011. The unit entitlement product is not expected to affect the load associated with the delivery period of bid products of this first solicitation, which is from January 1 to May 31, 2011.

The file “Redline_POLR_SMA_vs_FR_SMA_071709.doc” contains redline changes that reflect differences between the POLR SMA (revised February 12, 2008) under PPL Electric's Competitive Bridge Plan and the Default Service (Full Requirements) SMA (dated July 1, 2009) under PPL Electric's Default Service Procurement Plan. This file is available here.

The file “Redline_POLR_SMA_vs_Block_SMA_071709.doc” contains redline changes that reflect differences between the POLR SMA (revised February 12, 2008) under PPL Electric's Competitive Bridge Plan and the Default Service Block SMA (dated July 1, 2009) under PPL Electric's Default Service Procurement Plan. This file is available here.

Supplier Obligation = 1. 40625% x (total load of all default residential customers - (load from the NYPA contracts / 3) - 300 MW) 

The general formulation is correct, but the load from NYPA contracts is not divided by 3. Rather, NYPA contract supply is allocated to the classes based on relative load and not allocated 1/3 to each class. Also, this process (subtraction of load from the NYPA contracts/3) occurs within PJM's system, not PPL Electric's, where the load is treated as an import and is conducted as a financial transaction, not a physical transaction, within the systems. From a practical perspective, however, as the classes are not wholly different sizes, and as the NYPA contract is for 3 MW of contract demand with energy deliveries generally varying between 1 MW and 5 MW per hour (in the 2004 to 2008 period there were only 225 hours over 5000 MW), the distinction is not material. Also please note that while the formulation describes the hourly energy responsibility and loads that that will be used in ancillary service requirement determination it also applies to capacity (under PJM’s RPM construct). PPL Electric will be responsible for 300 MW of RPM capacity in connection with block supply and suppliers will be responsible for their share (1.40625% per tranche) of the residual capacity requirement after the allocated NYPA capacity and the 300 MW.

The Full Requirements SMA states that the seller is responsible for a percentage of Default Load for a Customer Group (“Specified Percentage”). Default Load is a defined term in the Full Requirements SMA which “means the total sales at the retail meter… …, less Block Supply and Unit Entitlement Supply.”

Please also refer to Contract/Load Following Full Requirements FAQ-1 for more information about this topic.

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:

This is correct. All ARRs will be held by PPL Electric during the term of the Default Service Procurement Plan, and any proceeds from the ARRs will be credited to customers proportionally.

As shown on Exhibit D to the Full Requirements SMA, ARR credits are assigned to Buyer. Please note that an update to the Full Requirements SMA dated July 23, 2009 corrects information in this Exhibit D.

Pursuant to sections 5.2 and 7.4 of the PJM Operating Agreement, share of Network Service User’s ARRs for each zone are reallocated as network load changes from one Network Service User to another within that zone. The Network Service User under the PJM OA is the entity using Network Transmission Service. As stated in section 2.3 of the Full Requirements SMA, PPL Electric is the network transmission customer responsible for the provision of Network Integration Transmission Service for PPL Electric customers.

As shown on Exhibit D to the Full Requirements SMA, ARR credits are assigned to Buyer. Please note that an update to the Full Requirements SMA dated July 23, 2009 corrects information in this Exhibit D.

Effective January 1, 2011 all ARRs allocated to suppliers under the competitive bridge plan will transfer back to PPL Electric pursuant to section 4.1 of the POLR SMA under PPL Electric’s Competitive Bridge Plan.

As shown on Exhibit D to the Full Requirements SMA, ARR credits are assigned to Buyer. Please note that an update to the Full Requirements SMA dated July 23, 2009 corrects information in this Exhibit D.

The block product will be netted from the “de-rated” load. The load of 1200 MW, which would include transmission and distribution losses, would first be derated for marginal losses and then the 300 MW would be subtracted.

Unit entitlement energy will likely be treated in a similar way. However, unit entitlement processes are not specified and unit entitlement energy will not be procured for the months that the first RFP will cover. Please check back when unit entitlement processes are specified. The NYPA transaction is settled financially, but the energy amount will be applied after de-rating. Hence the NYPA transaction will be handled in essentially the same manner.

“The Default Service Load for each of these Customer Groups for purposes of this Default Service RFP is the full requirements electricity service as recorded by PPL Electric and reported to the PJM Interconnection, LLC (“PJM”) for PPL Electric’s retail customers within that Customer Group, excluding customers that have chosen to take service from an Electric Generation Supplier (“EGS”). For the purposes of this RFP, the Default Service Load will be reduced by PPL Electric’s fractional percentage of committed capacity and energy obtained under long term contracts. For the Residential Group, this reduction includes 300 MW of energy and capacity purchased under separate block supply contracts, and up to an additional 50 MW of energy and capacity associated with a long-term unit entitlement supply contract.  Appropriate contract and performance data will be provided on PPL Electric's RFP Web site.”

NYPA is a long term contract and is clearly shown as such in the RFP data posted on the web site.

Yes.  As indicated in the Full Requirements RFP Rules, PPL Electric will buy 300 MW of RPM capacity. PPL Electric will be responsible each day for providing 300 MW of RPM capacity (plus allocated NYPA capacity) for the load of default service customers in the Residential Customer Group. The total RPM responsibility of all full requirements suppliers will be the RPM capacity required to serve the load of default service customers in the Residential Customer Group less the 300 MW and the NYPA capacity supplied by PPL Electric for that Group. An individual full requirements supplier’s responsibility for capacity will be its Specified Percentage times the total RPM responsibility of all full requirements suppliers of the Residential Customer Group.

Please see Other/Load Following Full Requirements FAQ-1 for more information.

The 50 MW unit entitlement supply is scheduled to begin June 1, 2011.  This supply has not been procured by PPL Electric and PPL Electric is required to conduct a collaborative with the parties involved in the PUC proceeding of the DSPP to establish the details of the unit entitlement supply.   PPL Electric expects that those details will be submitted to the PUC for approval.  PPL Electric expects to procure this supply through an RFP process.  The unit entitlement contract is expected to procure both energy and capacity. PJM will determine ancillary service responsibilities for PPL Electric and each supplier based on their individual loads and schedules.

Full requirements suppliers will be responsible for the residual energy and capacity needs of the Residential Customer Group.  The supply expected from this unit entitlement supply will be subtracted from the requirements of the DSPP load.  The terms of supply and the unit contingent risk will be determined from the collaborative process with all the parties, however PPL Electric expects to schedule a 50 MW block (24x7) supply from the unit entitlement purchase.

While details of the 50 MW unit entitlement purchase have not been developed, PPL Electric believes that a similar structure to how PPL Electric treats the 300 MW of Block Supply will apply to this unit entitlement supply as described in Other/Full Requirements FAQ-1.

For the Delivery Periods listed in section 1.1.7 of the RFP, is there a specific amount that has to be delivered each month or can the deliveries be made at any point in time during the stated Delivery Period?

Under the terms of the AEC SMA, there is a specific amount that has to be delivered each month of the delivery period (the “Monthly Settlement Quantity”). The Monthly Settlement Quantity must be transferred to PPL Electric’s GATS account within 40 calendar days of each month of the delivery period, and within 50 calendar days of the last month of the delivery period. Please consult section 2.3(c) and 2.3(d) of the AEC SMA for more information. Please note that a revised SMA dated July 6, 2009 corrects information in these sections.

First, please note that performance assurance is with respect to Aggregate Transactions, which mean that there will be netting of credit exposures across all other transactions for Default Service under Supply Master Agreements signed by the bidder and PPL Electric.

Should the AEC Supplier be a Party with PPL Electric only to the AEC SMA, then performance assurance will be with respect to only transactions under the AEC SMA. In such a case, the credit exposure will be calculated, with respect to each month remaining in the delivery period, as the sum of the products of each relevant month’s Monthly Settlement Quantity and the difference between that relevant month’s Forward Price and the Monthly Settlement Price.

Can you provide an example of the calculation for Performance Assurance under the AEC SMA?

First, let us assume that the AEC Supplier is a party with PPL Electric only to the AEC SMA. Let us also assume that there are two (2) remaining months left in the transaction delivery period, the monthly settlement quantity is 5,000 of TIER II AECs, and the monthly settlement price is $20/MWh. If the AEC forward price for both months is $27.5/MWh, then the credit exposure shall be equal to $75,000 (i.e., (10000 x ($27.5-$20). At any point during the term of the agreement, if the credit exposure is greater than the unsecured credit, then PPL Electric shall request that the AEC Supplier posts performance assurance in an amount equal to the difference between the credit exposure and the unsecured credit. As stated in Section 12.1 of the AEC SMA, “notwithstanding the above, Seller shall only be required to post the required Performance Assurance to the extent the amount of required Performance Assurance is equal to or greater than $50,000. Subsequent and incremental requests for Performance Assurance shall be in $25,000 increments.”

No. The AEPS obligations of winning suppliers in the AEC RFP will be specified in the Transaction Confirmation, and the AEPS obligations of winning suppliers in the Full Requirements RFP will be specified in Exhibit B to the Full Requirements SMA. These documents will be provided to the winning suppliers on the day the Pennsylvania Utility Commission approves the bid results of a solicitation. Thereafter, these documents will be the binding obligation of the winning suppliers, which will not change.

Can you confirm that for the AEC RFP the Monthly Settlement Quantity with the exception of the last month is equal to the following:

(hours in calendar month/total hours in the delivery period) x the specified amount of AECs sold by Seller.

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)).

For more information about the AEPS Act, please visit: http://www.puc.state.pa.us/electric/electric_alt_energy.aspx