Workshop on PJM ARR and FTR Market 2012/ PDF Free Download

Workshop on PJM ARR and FTR Market 2012/2013 www.pjm.com PJM 2012 1

Training Objectives At the completion of this training, you should be able to Understand the concepts and principles of Auction Revenue Rights and Financial Transmission Rights Understand how to participate in the Annual ARR Allocation and FTR Auctions Understand the Market Settlements for FTRs and ARRs Describe the Market Participant activities that can be performed using PJM eftr 2

Agenda (AM) Introduction / FTR Market Schedule Overview of Financial Transmission Rights (FTRs) Overview of Auction Revenue Rights (ARRs) Overview of Simultaneous Feasibility Test (SFT) Break Long-Term Transmission Rights Annual Allocation Process Lunch 3

Agenda (PM) FTR Auctions & Bilateral Trading Market Settlements Annual ARR Allocation Example Annual FTR Auction Example 4

Appendices and References Appendix A: FTR Auction Clearing Mechanism Appendix B: eftr - Market User Interfaces Appendix C: ARR Reassignment Example Other Documents about FTRs available on PJM.com FTR Manual eftr User Guide Frequently Asked Questions 5

Introduction www.pjm.com PJM 2012 7

What are ARRs Auction Revenue Rights are entitlements allocated annually to Firm Transmission Service Customers that entitle the holder to receive an allocation of the revenues (or charges) from the Annual FTR Auction 8

Financial Transmission Rights are financial instruments awarded to bidders in the FTR Auctions that entitle the holder to a stream of revenues (or charges) based on the hourly Day Ahead congestion price differences across the path What are FTRs? 9

ARR/FTR Relationship ARRs provide revenue stream to the firm transmission customer to offset purchase price of FTRs Entire PJM System Capability Annual Allocation ARRs Allocated (MWs) Auction Revenue Rights Annual FTR Auction FTRs Awarded To Bidders (MWs & Price) Auction Revenue 10

FTR Market Schedule www.pjm.com PJM 2012 11

2012/2013 ARR/FTR Annual and Long Term Auction Timeline 12

2012/2013 Annual ARR/FTR Market Timeline 13

Annual ARR/FTR Market Timeline Annual Allocation Stage 1A Participants may relinquish Stage 1 ARRs Annual Allocation Stage 1B Annual Allocation Stage 2 (3 Rounds) ARR Trading Annual FTR Auction (4 Rounds) February 29, 2012 March 5, 2012 March 12, 2012 14 April 2, 2012 April 3, 2012 April 30, 2012

Date Annual Allocation Stage 1 Activity February 29, 2012 Window opens at 0001 to submit requests for ARRs for Stage 1A. March 1, 2012 March 2, 2012 March 5, 2012 March 6, 2012 March 8, 2012 March 9, 2012 Window closes for Stage 1A. All ARR requests submitted by 1700 via eftr. Deadline for PJM to post awarded ARRs for Stage 1A by 1700. Window opens at 0001 to submit requests for ARRs for Stage 1B. Window closes for Stage 1B. All ARR requests submitted by 1700 via eftr. Deadline for PJM to post awarded ARRs for Stage 1B by 1700. Participants may relinquish Stage 1 ARRs. 15

Annual Allocation Stage 2 Opens 0001 Closes 1700 Results 1700 Round 1 March 12, 2012 March 13, 2012 March 16, 2012 Round 2 March 19, 2012 March 20, 2012 March 23, 2012 Round 3 March 26, 2012 March 27, 2012 March 30, 2012 u*arrs will start June 1, 2012, and end May 31, 2013 16

Date April 2, 2012 Activity ARR trading period ends. ARR Trading 17

Annual FTR Auction Opens 0001 Closes 1700 Results 1700 Round 1 April 3, 2012 April 5, 2012 April 9, 2012 Round 2 April 10, 2012 April 12, 2012 April 16, 2012 Round 3 April 17, 2012 April 19, 2012 April 23, 2012 Round 4 April 24, 2012 April 26, 2012 April 30, 2012 u*ftrs will start June 1, 2012, and end May 31, 2013 18

Long Term FTR Auction Opens 0001 Closes 1700 Results 1700 Round 1 June 1, 2012 June 5, 2012 June 12, 2012 Round 2 September 4, 2012 September 6, 2012 Round 3 December 3, 2012 December 5, 2012 September 13, 2012 December 12, 2012 u*ftrs will start June 1, 2013, June 1, 2014, or June 1, 2015 19

Overview of Financial Transmission Rights (FTRs) www.pjm.com PJM 2012 21

What are FTRs? Financial Transmission Rights are financial instruments awarded to bidders in the FTR Auctions that entitle the holder to a stream of revenues (or charges) based on the hourly Day Ahead congestion price differences across the path 22

Challenge: Why do we need FTRs? LMP exposes PJM Market Participants to price uncertainty for congestion cost charges During constrained conditions, PJM Market collects more from loads than it pays generators Solution: Provides ability to have price certainty FTRs provide hedging mechanism that can be traded separately from transmission service? 23

Characteristics of FTRs Economic value based on Day-Ahead Congestion Prices Defined from source to sink can be in form of obligation or option obligation can be benefit or liability option can be benefit but never liability Financial entitlement, not physical right Independent of energy delivery Must be simultaneously feasible 24

Economic Value of FTRs FTR Target Allocation = (FTR MW ) * (Congestion Price FTR Sink Congestion Price FTR Source) FTR Target Allocation is equal to the FTR MW amount times the congestion price difference from the FTR sink point to the FTR source point Congestion Price based on the clearing prices from Day-Ahead Market If Congestion Price FTR Sink < Congestion Price FTR Source the FTR is a liability if FTR defined as Obligation the FTR has zero value if defined as Option 25

How are FTRs Acquired? FTRs are acquired in several market mechanisms 1. Annual FTR Auction multi - round entire system capability minus approved Long-Term FTRs 2. Long-Term FTR Auction multi - round purchase residual system capability assuming the self-scheduling of ARRs 3. Monthly FTR Auction single - round purchase left over capability 4. FTR Secondary Market bilateral trading 26

Types of FTR Products FTRs can be acquired in two forms FTR Obligations FTR Options 27

What are FTR Obligations Worth? Benefit the hourly congestion value is positive FTR same direction as congested flow Liability the hourly congestion value is negative FTR opposite direction as congested flow 28

What are FTR Options Worth? A Benefit the hourly congestion value is positive FTR same direction as the congested flow. Neither a Benefit or a Liability the hourly congestion value is zero FTR opposite direction to the congested flow. FTR Option cannot have negative value 29

FTR Credits and Congestion Charges Congestion Charge = MWh*(Day-ahead Sink Congestion Price - Day-ahead Source Congestion Price) FTR Credit = MW*(Day-ahead Sink Congestion Price - Day-ahead Source Congestion Price) 30

FTR Obligation is a Benefit Thermal Limit FTR Obligation = 100 MW Bus A Source (Sending End) Congestion Price = $15 Energy Delivery = 100 MWh Bus B Sink (Receiving End) Congestion Price = $30 Congestion Charge = 100 MWh * ($30-$15) = $1500 FTR Obligation Credit = 100 MW * ($30-$15) = $1500 31

FTR Obligation is a Liability Thermal Limit FTR Obligation = 100 MW Bus A Source (Sending End) Congestion Price = $15 Energy Delivery = 100 MWh Bus B Sink (Receiving End) Congestion Price = $30 Congestion Charge = 100 MWh * ($30-$15) = $1500 FTR Obligation Credit = 100 MW * ($15-$30) = $-1500 32

FTR Option is a Benefit Thermal Limit FTR Option= 100 MW Bus A Source (Sending End) Congestion Price = $15 Energy Delivery = 100 MWh Congestion Price = $30 Congestion Charge = 100 MWh * ($30-$15) = $1500 FTR Option Credit = 100 MW * ($30-$15) = $1500 Bus B Sink (Receiving End) 33

FTR Option is Neither a Benefit/Liability Thermal Limit FTR Option= 100 MW Bus A Source (Sending End) Congestion Price = $15 Energy Delivery = 100 MWh Bus B Sink (Receiving End) Congestion Price = $30 Congestion Charge = 100 MWh * ($30-$15) = $1500 FTR Option Credit = 100 MW * ($15-$30) = $-1500 = $0 ***When calculated, the FTR Option Credit is negative, therefore the economic value will equal zero.****** 34

Summary FTRs are financial instruments used to hedge congestion costs FTRs can be acquired in the Annual FTR Auction, Long-Term FTR Auction, Monthly FTR Auction, or Secondary Market FTRs can be Obligations or Options obligation can be benefit or liability option can be benefit but never liability FTRs must be simultaneously feasible 35

Overview of Auction Revenue Rights (ARRs) www.pjm.com PJM 2012 37

What are ARRs? Auction Revenue Rights are entitlements allocated annually to Firm Transmission Service Customers that entitle the holder to receive an allocation of the revenues (or charges) from the Annual FTR Auction 38

Annual ARR Allocation Allocated to Firm Transmission Service Customers annually in a two-stage allocation process First stage protects native load utilization of the transmission system providing long-term certainty Second stage provides flexibility to adjust hedging paths annually property rights allocated to Firm Transmission Customers as Auction Revenue Rights Supports retail programs by reassigning ARRs/FTRs as load switches between LSEs within planning period 39

Characteristics of ARRs Economic value based on LMPs from the Annual FTR Auction Defined from source to sink Only available as an obligation obligation can be benefit or liability Financial entitlement, not physical right Must be simultaneously feasible 40

Economic Value of ARR ARR Target Allocation = (ARR MW ) * (LMP ARR Sink - LMP ARR Source ) ARR Target Allocation is equal to the ARR MW amount times the average price difference from the ARR sink point to the ARR source point over the 4 rounds LMPs based on the average nodal clearing prices over the 4 rounds of the Annual FTR Auction ARRs can be a benefit or a liability 41

How are ARRs Acquired? ARRs are acquired in the following mechanisms 1. Annual Allocation Auction Revenue Rights (ARRs) requested by Firm Transmission Customers are allocated on an annual basis 2. Daily ARR Reassignment ARRs allocated for the planning period will be reassigned on a proportional basis within a zone as load switches between LSEs within the planning period 42

What can the holder do with the ARR? Convert ARR into FTR by self-scheduling FTR into Annual Auction on exact same path as ARR Reconfigure ARR by bidding into Annual Auction to acquire FTR on alternative path or for alternative product May retain allocated ARR and receive associated allocation of revenues from the auction 43

Daily ARR Reassignment ARRs allocated for the planning period will be reassigned daily on a proportional basis within a zone as load switches between LSEs within the planning period. An LSE that loses load in a zone will lose ARRs if the LSE has a net positive economic ARR position for that zone An LSE that loses load in a zone will not lose ARRs if the LSE has a net negative economic ARR position for that zone An LSE that opted for a direct allocation of FTRs and that loses load will lose a proportional share of each FTR 44

Daily ARR Reassignment Process STEP 1 How Does Load Shifts? STEP 2 Who Loses ARR? STEP 3 Who Gains ARR? Compare each LSE s daily deviation of Network Peak Load in zone Analyze each LSE s net economic position. For each LSE losing load AND have a net positive position for that zone, a. determine load lost % b. reduce each ARR owned by that percentage Assign total set of forfeited ARRs to LSEs that gain load in zone a. determine percentage of ARRs to be assigned to each LSE gaining load b. assign LSE gaining load % of each ARR in this set of forfeited ARRs 45

Daily ARR Reassignment March A reassignment will occur on June 1 by comparing the actual June 1 load contribution to the estimated June 1 load contribution Daily ARR Reassignments Jan 1 June 1 ARRs are allocated in March for the next planning period using an estimate of peak load contributions for June 1 An ARR reassignment for January 1 will not be conducted because new zonal loads are uploaded and allocated on January 1 46

Residual ARRs ARRs prorated in Stage 1 of the Annual ARR Allocation may be allocated Residual ARRs for increased transmission capability made available by certain transmission upgrades made during the planning year that were not modeled in the Annual ARR Allocation. Residual ARR MWs plus previously awarded Stage 1 and Stage 2 MWs cannot exceed the Network Service Peak Load value for a particular participant Residual ARRs are effective the first month the increased transmission capability is modeled in the Monthly FTR Auction Economic value of Residual ARRs are based on the MW amount and the nodal clearing price difference between the source and sink nodes for FTR Obligations resulting from each monthly FTR Auction the Residual ARR is effective. 47

Summary ARRs entitle the holder to receive allocation of Annual FTR Auction revenues ARRs are allocated to Firm Transmission Service Customers ARRs may be converted to an FTR by self-scheduling the ARR into the Annual FTR Auction ARRs are reassigned on a proportional basis within a zone as load switches between LSEs within the planning period ARRs are only available as an obligation obligation can be benefit or liability ARRs must be simultaneously feasible Residual ARRs may be available within a planning period for increased transmission capability 48

Overview of Simultaneous Feasibility Test (SFT) www.pjm.com PJM 2012 49

What is a Simultaneous Feasibility Test? Test to ensure that all subscribed transmission entitlements are within the capability of the existing transmission system Test to ensure the PJM Energy Market is revenue adequate under normal system conditions NOT a system reliability test NOT intended to model actual system conditions 50

Feasibility of ARRs and FTRs ARRs must be simultaneously feasible to ensure that Annual FTR Auction revenues are sufficient to cover ARR Target Allocations FTRs must be simultaneously feasible to ensure that total congestion charges collected from Day Ahead and Balancing Markets are sufficient to cover FTR Target Allocations 51

Test Conditions and Criteria FTRs or ARRs are modeled as generation at source point and load at sink point Single contingency test criteria Perform DC powerflow analysis to evaluate ability of all system facilities to remain within normal thermal ratings evaluate ability to sustain the loss of any single contingency event with all system facilities remaining within applicable short-term, emergency ratings 52

SFT Data Inputs u Uncompensated Parallel Flow Injections u Transmission Outages u Existing FTRs or ARRs u Facility Ratings u PJM Network Model u List of Contingencies u Interface Ratings SFT (DC Powerflow) 53

SFT Example #1 180 MW 300 MW A Net Flow = 480 MW 500 MW Rating B 180 MW 300 MW FTR 1 : 300 MW Obligation from A to B FTR 2 : 180 MW Obligation from A to B Net Flow on Line A-B = 480 MW Line A-B Flow = Line A-B Rating therefore both FTRs are simultaneously feasible 54

SFT Example #2 300 MW 300 MW A Net Flow = 600 MW 500 MW Rating B 300 MW 300 MW FTR 1 : 300 MW Obligation from A to B FTR 2 : 300 MW Obligation from A to B Net Flow on Line A-B = 600 MW Line A-B Flow > Line A-B Rating therefore both FTRs are NOT simultaneously feasible 55

Revenue Adequacy using SFT Examples Day Ahead Market Congestion Price = $10 Congestion Price = $20 Energy Flow = 500 MW A B 500 MW Rating Day Ahead Congestion Charge = 500 MW ($20 - $10) = $5,000 FTR Target Allocation (using SFT Example 1 FTRs) Total FTR Target Allocation = 480 MW ($20 - $10) = $4,800 FTR Target Allocation (using SFT Example 2 FTRs) Total FTR Target Allocation = 600 MW ($20 - $10) = $6,000 56

SFT Example #3 Net Flow = 500 MW 1000 MW 500 MW A 500 MW Rating B 1000 MW 500 MW FTR 1 : 500 MW Obligation from B to A FTR 2 : 1000 MW Obligation from A to B Net Flow on Line A-B = 500 MW Line A-B Flow = Line A-B Rating therefore both FTRs are simultaneously feasible 57

SFT Example #4 1000 MW 500 MW A Net Flow = 500 MW or 1000 MW 500 MW Rating B 1000 MW 500 MW FTR 1 : 500 MW Option from B to A FTR 2 : 1000 MW Obligation from A to B Net Flow on Line A-B = 500 MW - or Net Flow on Line A-B = 1000 MW (must ignore counterflow created by Option) Line A-B Flow > Line A-B Rating therefore both FTRs are NOT simultaneously feasible 58

Revenue Adequacy using SFT Examples Day Ahead Market Congestion Price = $10 Energy Flow = 500 MW Congestion Price = $20 A B 500 MW Rating Day Ahead Congestion Charge = 500 MW ($20 - $10) = $5,000 FTR Target Allocation (using SFT Example 3 FTRs) FTR 1 Target Allocation = 500 MW ($10 - $20) = -$5,000 FTR 2 Target Allocation = 1000 MW ($20 - $10) = $10,000 Total FTR Target Allocation = $5,000 FTR Target Allocation (using SFT Example 4 FTRs) FTR 1 Target Allocation = 500 MW ($10 - $20) = 0 FTR 2 Target Allocation = 1000 MW ($20 - $10) = $10,000 Total FTR Target Allocation = $10,000 59

Maintaining Feasibility Feasibility of requests is maintained by: Annual Allocation requests prorated in proportion to MWs requested and inverse proportion to effect on binding constraint Annual/Long-Term/Monthly Auctions requests awarded to highest bidder 60

Long-Term Transmission Rights 61

LTTR Rules Provide a LTTR based on a priority Stage 1A ARR allocation for base load that ensures longer term certainty with flexibility to opt-out on an annual basis. Creates a link between the PJM planning process and the Stage 1A ARR allocation to ensure transmission system is upgraded to maintain Stage 1A ARRs for base load plus projected 10 year growth of base load Provides a mechanism to establish new Stage 1A resources to cover base load plus projected 10-year growth of base load. Provides a mechanism to replace existing stage 1 resource points with alternative stage 1 resources Provides a mechanism for identifying upgrades and cost needed to support requests for 30-year ARRs. Provides a process to purchase Long-Term FTRs on an annual basis that covers one or three planning years. 62

Stage 1A ARR Allocation Network customers request stage 1A ARRs up to their pro-rata share of the zonal base load from historic resources Qualifying transmission customers request stage 1A ARRs up to 50% of transmission reservation MW amount Maintains flexibility of an annual ARR by allocating each year in annual allocation process giving holder ability to opt-out A savings clause protects stage 1A ARRs for a 10- year period if subsequent statutory or regulatory changes are introduced A link between the PJM planning process and the Stage 1A ARR allocation to ensure transmission system is upgraded to maintain Stage 1A ARRs for base load plus projected 10 year growth of base load 63

Stage 1A link to Planning Process PJM will conduct annual SFT of Stage 1A ARRs to assess feasibility for each year remaining in the term of the rights Zonal growth rate applied to each zone s base load to develop zonal base loads for years 2 through 10 SFT of all requested Stage 1A ARRs plus additional ARRs to cover load growth Zonal load growth covered by "dispatching" the Stage 1 resources available to each zone in economic order according to historic LMP values If an SFT violation occurs in any year of the analysis then upgrade is identified and recommended for inclusion into the PJM RTEP 64

Addition of New Stage 1 Resources New Base resources may be designated if the MW amount of a zone s Stage 1 resources are less than the zonal Base Load. must be either self-owned resources or supply contracts for firm capacity and energy having a contract term of ten years or greater new resource must be simultaneously feasible with all existing Stage 1 and 2 ARRs new resource must be simultaneously feasible with all eligible Stage 1A ARRs in 10-year SFT model 65

Alternate Stage 1 Resources Network Customers may replace, on a going forward basis, its current Stage 1 historic resource points and MWs with alternative Stage 1 source point(s) of an electrically equivalent MW amount Electrically equivalent defined as consuming an equal or lesser amount of transmission capability on constraints without creating new overloads must be either self-owned resources or supply contracts for firm capacity and energy having a contract term of ten years or greater must be simultaneously feasible with all existing Stage 1 and 2 ARRs must be simultaneously feasible with all eligible Stage 1A ARRs in 10-year SFT model Total Alternative Stage 1 source point(s) MWs allowed cannot exceed MWs associated with original Stage 1 ARRs 66

30-Year Incremental ARRs Section 7.8 of Schedule 1 of OA gives any party the right to obtain LT 30-year Incremental ARRs provided the party fully funds the upgrade needed to support the requested rights Part VI of Tariff sets up a single queue for processing these requests along with interconnection requests (generation and merchant transmission) and transmission service requests On Attachment EE, Customer specifies IARR source, sink and MW amount PJM will assess feasibility of request against existing base system ARR capability and stage 1A ARR capability for future 10 year period In system impact study, PJM will determine upgrades and cost needed to make the request feasible In accordance with existing rules, the customer funding such transmission upgrades will be entitled to the incremental 30-year ARRs created by the upgrade. 67

Long-Term FTRs On an annual basis, subsequent to the annual FTR auction, PJM conducts a long-term auction for FTRs effective for the three planning years following the planning year of the current annual FTR auction. The Long-Term FTR Auction offers for sale the residual system capability available assuming the self-scheduling of ARRs that may occur on an annual basis. These ARRs will be modeled as fixed injections and withdrawals in the Long-Term FTR Auction along with already approved Long-Term FTRs The Long-Term FTR Auction is a multi-round auction consisting of three rounds in which one-third of the feasible FTR capability will be offered in each round. FTR Option products are not available in the Long-Term FTR Auctions FTR acquired in the Long-Term FTR Auctions may have terms of one year, for each of the three planning years covered by the auction, or a term of three years, for the entire three-year period covered by the auction. 68

Annual Allocation Process www.pjm.com PJM 2012 69

Characteristics of the Annual Allocation Long Term Allocation on an annual basis ARRs are acquired for duration of Planning Period Allocated to Firm Transmission Service Network Integration Service Firm Point to Point Entire Capability of the Transmission System Within Planning Period, Network ARRs are reassigned as load shifts Shorter term Pt-to-Pt ARRs may be requested via OASIS 70

Characteristics of the Annual Allocation (cont.) Two Stage Allocation Process Stage1 assigns candidate ARR sources for each zone from resources historically designated to serve load in the zone Stage 1A for historical resources up to base load Base Load defined as minimum of daily peak loads for each transmission zone from previous year escalated by one-year s projected load growth. Maximum MW available to each historical resource will be share of the historical resource capability. Qualifying Firm Point-to-Point Customers may request up to 50% of the qualifying transmission service reservation MW level Stage 1B for historical resources up to peak load Maximum MW available to each historical resource will be share of the historical resources capability minus Stage 1A MWs allocated from resource. Qualifying Firm Point-to-Point Customers may submit request for the remainder of their qualifying transmission service reservation MW level that was not covered by Stage 1A ARR MWs 71

Characteristics of the Annual Allocation (cont.) Stage 2 is a 3 round iterative approach which allows LSEs to request additional ARRs from a variety of potential ARR source points Total MWs requested by LSE cannot exceed LSE s share of zonal peak load and each round of Stage 2 is limited to 1/3 of the remaining peak load amount not covered in Stage 1 allocation 72

Stage 1A and 1B Stage 2 Annual Allocation ustage 1A and Stage 1B performed separately with both using a Single Allocation Process uthe ARR source is designated from Generation Resources that historically served load in each transmission zone or historic load aggregation Zone uentire system capability is available for allocation u3 Round Allocation Process uthe ARR source is designated from any generation bus, hub, zone or interface u1/3 of remaining system capability allocated in each round Sink points are zone or aggregate where load is located 73

Stage 1 Annual Allocation Process Stage 1 Annual Allocation Process Stage 1A performed prior to Stage 1B each LSE in a zone assigned a pro-rata amount of the MW capability from each historical generation resource assigned to the zone LSE chooses the set of ARRs that it wants to request based on the resources assigned ARRs must source at the designated resource and sink at the LSE s aggregate load in the transmission zone or load aggregation zone ARR request is limited to an amount not greater that the assigned resource MW capability Total ARR MW request cannot exceed LSE share of zonal base load for Stage 1A and zonal peak load in stage 1B 74

Stage 1 Annual Allocation Process Stage 1 - Annual Allocation Process (cont) Firm Pt-to-Pt requests are made for reservations deemed as Qualifying up to 50% of Reservation MW level for Stage 1A and remainder in Stage 1B PJM performs Simultaneous Feasibility Test (SFT) to determine the set of ARRs that can be awarded to each LSE PJM notifies each LSE of the ARR awards and binding constraints from Stage 1A and Stage 1B A participant may surrender any portion of the ARRs awarded in Stage 1 prior to commencement of Stage 2 subject to Simultaneous Feasibility 75

Historical Generation Resource Stage 1 - Valid Sources PJM determines a set of eligible ARR sources for each transmission zone or for each historic load aggregation zone within a transmission zone based on the historical reference year that corresponds to the LMP-based market implementation for the transmission zone Historic load aggregation zone is sub-region of a zone that was served under a separate set of supply contracts than other load in zone 1998 = Reference Year for PJM 2002 = Reference Year for APS and RECO 2004 = Reference Year for ComEd, AEP, Dayton, DUQ 2005 = Reference Year for Dominion 2010 = Reference Year for ATSI 76

Stage 1 - Annual Allocation Process Stage 1 Opens MW Capability Assigned to each LSE Requests Submitted Simultaneous Feasibility Test Requests Approved PJM will assign each LSE a prorata amount of the MW capability from each historical generation resource LSE submits ARR request via eftr LSE chooses the set of ARRs that it wants to request based on the resources assigned Request is limited to an amount not greater than the designated MW Amount Limited to LSEs share of zonal base load for Stage 1A and peak load for Stage 1B Qualifying Pt-to-Pt customers submit ARR request via email/spreadsheet All requests are tested for feasibility by PJM. Approved ARRs and binding constraints are posted on eftr 77

Stage 1 Reminder to AEP Zonal Customers In Stage 1, AEP zonal customers with zonal settlement will request ARRs that sink at the AEP w.o. MON Power aggregate and the MON Power aggregate Pro-rata share of AEP NSPL is allocated to the AEP w.o. MON Power and MON Power stage 1 zones AEP stage 1 resources are assigned to load located in the AEP w.o. MON Power aggregate and will sink at this aggregate APS stage 1 resources are assigned to load located in MON Power aggregate and will sink at this aggregate In Stage 2, AEP zonal customers with zonal settlement will request ARRs that sink at the AEP zone 78

Stage1 Configuration for AEP Zonal Customers AMOS 1 800 MW HATFIELD 1 513.6 MW 16.4 MW APS AEP w.o. MON Power 1.2% 98.8% MON Power 79

Stage 2 Annual Allocation Process Stage 2 Annual Allocation Process Stage 2 is an iterative allocation process that consists of three sequential rounds, with 1/3 of the remaining system ARR capability allocated in each round LSE may view results of each round before submitting ARR request for the next round In each round, LSE chooses the set of ARRs that it wants to request from any generator bus, hub, external interface or zone Total ARR MWs requested by LSE in each round of Stage 2 is limited to 1/3 of the remaining peak load amount not covered in Stage 1 allocation 80

Stage 2 Annual Allocation Process Stage 2 - Annual Allocation Process (cont) Qualifying Pt-to-Pt requests in each round of Stage 2 is limited to 1/3 of the service level not covered in Stage 1 allocation Firm Pt-to-Pt Transmission not deemed as Qualifying but subject to base transmission charge eligible for ARR requests in Stage 2 PJM performs Simultaneous Feasibility Test (SFT) to determine the set of ARRs that can be awarded to each LSE PJM notifies each LSE of the ARR awards and binding constraints after each round of Stage 2 81

Stage 2 Annual Allocation Process Stage 2 Opens Requests Submitted in each Round Simultaneous Feasibility Test Each Round Closes Requests Approved LSE submits ARR request via eftr LSE chooses the set of ARRs from any generator bus, hub, external interface or zone ARR request are limited to 1/3 of the Network customer s Peak load remaining unallocated after Stage 1 Pt-to-Pt customers submit ARR request via email/spreadsheet All requests are tested for feasibility by PJM 1/3 of remaining system capability awarded in each round Approved ARRs and binding constraints are posted on eftr after each round Stage 2 is an iterative allocation process that consists of four sequential rounds, with 1/3 of the remaining system ARR capability allocated in each round 82

Simultaneous Feasibility Test All ARR requests are tested for feasibility. If all ARR requests are simultaneously feasible then all requests can be approved If all ARR requests are not simultaneously feasible then ARRs are allocated proportional to MW requested and inversely proportional to effect on constraint Prorated ARR MW Value = Line Capacity * (Requested ARRs MW) * (1) (Total ARR MWs) (effect on constraint) 83

A B Proration Example C D Line AB Capacity = 50 MW Requests # Requested ARRs Path Effect on Line AB Line AB Flow (FTRs) #1 200 MW A to B.50 100 MW #2 200 MW C to D.25 50 MW Total Flow on Line AB 150 MW line flow exceeds line capability by 100 MW Requests cannot be fully allocated without exceeding Line A-B capacity 84

A B Proration Example (cont.) C D Line AB Capacity = 50 MW Requests # Requested ARRs (FTRs) Path Prorated ARRs (FTRs) Effect on Line AB Line AB Flow #1 200 MW A to B 50 MW [50MW (200MW / 400MW) ( 1 / 0.50)] #2 200 MW C to D 100 MW [50MW(200MW / 400MW)( 1 / 0.25) Total Flow on Line AB.50 25 MW.25 25 MW 50 MW ARR requests can be fully allocated 50 MW line capability fully subscribed 85

Summary Auction Revenue Rights are allocated to Firm Transmission Service customers (Network and Firm Pointto-Point) ARRs are requested annually during the Annual Allocation and are acquired for the entire next planning period The Annual Allocation is a two-stage allocation process All Requests must be simultaneously feasible Within the Planning Period, Network Service ARRs are reassigned as load shifts within a zone Requests associated with shorter term point-to-point service may be made via OASIS 86

Market User Interfaces for Annual Allocation www.pjm.com PJM 2012 87

ARR Requests - Stage 1 88

ARR Requests - Stage 1 89

ARR Requests - Stage 1 90

ARR Requests Stage 2 91

ARR Results 92

FTR Auctions & Bilateral Trading www.pjm.com PJM 2012 93

Characteristics of the Annual FTR Auction Entire FTR capability of the transmission system minus approved Long-Term FTRs Multi-product auction FTR Options & FTR Obligations Multi-round auction consisting of 4 rounds with 25% available in each round Multi-period auction On Peak, Off Peak, 24 Hour FTRs have a term of one-year 95

Multi-round FTR Auction The Annual FTR Auction is a multi-round auction consisting of 4 rounds 25% of the feasible FTR capability of the PJM system is awarded in each round FTRs that were awarded in Long-Term FTR Auctions that are effective for Annual Auction interval are modeled as fixed injections FTRs awarded in one round are modeled as fixed injections in future rounds FTRs awarded in Long-Term FTR Auction may be offered for sale in Annual Auction FTRs that are awarded in one round may be offered for sale in subsequent rounds FTRs that are self-scheduled must be submitted in Round 1 96

Annual FTR Auction Process Round Begins Quotes Entered Market Clears FTRs Awarded Calculate ARR Target Allocation Round Ends 25% of the feasible system capability is awarded in each of the four rounds FTRs that were awarded in Long-Term FTR Auctions that are effective for Annual Auction interval are modeled as fixed injections Awarded FTRs from each round are modeled as fixed injections in next Round FTRs awarded in Long-Term FTR Auctions may be offered for sale in Annual Auction FTRs that are awarded in one round may be offered for sale in subsequent rounds Auction Revenues distributed to ARR Holders in proportion to the economic value of the ARRs 97

Self Scheduled FTRs ARR holders have the option to convert their ARRs into FTRs by Self-Scheduling FTRs in the Annual FTR Auction only Characteristics of Self Scheduled FTRs Same Source and Sink of ARR Up to ARR MW amount Price Taker 24 Hour FTR Obligation Scheduled in Round 1 of Annual FTR Auction 25% of MW amount will clear in each round 98

Characteristics of the Long-Term FTR Auctions Residual FTR capability of the transmission system left over capability assuming Self-Scheduling of current planning year ARRs Approved Long-Term FTRs modeled as fixed injections. Single-product auction FTR Obligations only Multi-round auction Consisting of three rounds held 3 months apart with onethird available in each round. Multi-Period auction On Peak, Off Peak, 24 Hour Any of next three planning years or the full three year period following the planning year of the current annual FTR auction FTRs have a term of one year or three years 99

Long-Term FTR Auction Valid Bidding Periods Individual year in next three planning periods after current Annual Auction FTRs Three-year period following current Annual Auction FTRs Long-Term Auction FTRs Annual Auction FTRs Year 1 On/Off On/Off On/Off Year 2 Year 3 Year 4 100

Multi-round FTR Auction The Long-Term FTR Auction is a multi-round auction consisting of 3 rounds One-third of the feasible FTR capability of the PJM system is awarded in each round The Long-Term FTR Auction offers for sale the residual system capability available assuming the self-scheduling of ARRs that may occur on an annual basis. These ARRs will be modeled as fixed injections and withdrawals in the Long-Term FTR Auction along with already approved Long-Term FTRs. FTRs that are awarded in previous Long-Term FTR Auctions that are effective for the market interval may be sold in either round FTRs that are awarded in round one may be offered for sale in successive rounds 101

Characteristics of the Monthly FTR Auctions Residual FTR capability of the transmission system left over capability from Long-Term and Annual FTR Auction Multi-product auction FTR Options & FTR Obligations Single-round auction Multi-Period auction On Peak, Off Peak, 24 Hour Any of next three individual calendar months or remaining full planning period quarters FTRs have a term of one month or a three month quarter 102

Monthly FTR Auctions Valid Bidding Periods Next 3 individual calendar months remaining in planning period Any complete planning period quarter remaining in planning period Jun Jul Aug Sep-Oct-Nov Dec-Jan-Feb Mar-Apr-May On/Off On/Off On/Off On/Off On/Off On/Off 103

FTR Secondary Market Bilateral Trading of existing FTRs only Bulletin Board system in PJM eftr FTRs can be split into smaller increments (duration/mw/period) that total the original FTR New owner takes on cost responsibility of purchased FTR FTRs cannot be reconfigured path and product type (Option or Obligation) must remain same Successful trades in eftr transfer ownership adjustments in Monthly Billing Statement independent trades outside of eftr are not adjusted in Monthly Billing Statement 104

Comparison of FTR Auctions Annual FTR Auction Long-Term FTR Auction Monthly FTR Auctions Capability Auctioned Entire FTR capability of the transmission system minus approved Long- Term FTRs Residual FTR capability of the transmission system assuming Self- Scheduling of current planning year ARRs Residual FTR capability of the transmission system Auction Format Multi Round Multi Round Single Round FTR Products FTR Obligations FTR Options FTR Obligations FTR Obligations FTR Options FTR On peak On peak On peak Class Types Off peak Off peak Off peak 24 Hour 24 Hour 24 Hour FTR One Year One Year One Month Period One three-year planning period One three-month planning period quarter 105

Valid Sources and Sinks Annual and Long-Term Monthly Monthly FTR Auctions FTR Auctions FTR Auctions Next Calendar Month Quarters and 2 nd /3 rd Month FTR Obligations Valid Sources & Sinks are limited to: Hubs Zones Aggregates Interface Buses Generator Buses Valid Sources & Sinks include any single bus or combination of buses for which a Day-ahead LMP is calculated & posted: Hubs Zones Aggregates Valid Sources & Sinks are limited to: Hubs Zones Aggregates Interface Buses Generator Buses Interface Buses Generator/Load Buses FTR Options* Only a subset of paths will be eligible for FTR Options in order to prevent potential auction clearing performance issues *Option Product not available in Long-Term FTR Auction 106

Auction Clearing Mechanism The FTR Auctions maximize the quote based bid value of a set of simultaneous feasible FTRs awarded in the auction. The FTR Auctions evaluate the simultaneous feasibility of all outstanding FTRs, in conjunction with new FTRs to be awarded or surrendered by Market Participants 107

FTR Auction Process Bids and Offers for FTRs are submitted via eftr Quotes Entered Market Clears FTRs Awarded Winning Quotes determined Highest bid-based valued combination of simultaneously feasible FTRs are selected Auction Results are posted 108

Post FTR Auction Input and Output Uncompensated Parallel Flow Injections Transmission Outage Schedules Pre-existing FTRs Facility Ratings FTR Quotes (Buy or Sell) PJM Network Model List of Contingencies Aggregate Price Definitions FTR Auction Software FTRs Awarded in Auction FTRs Sold in Auction Nodal Prices Option Clearing Prices Aggregate Prices Binding Constraints 109

Multi-product FTR Auction FTRs in Annual and Monthly FTR Auctions can be acquired in two forms FTR Obligations FTR Options 110

Auctioning of FTR Options The clearing price of an FTR Option Buy Bid will never be less than zero can t be paid for something that has no downside The clearing price of an FTR Option will always be greater than or equal to the clearing price of an FTR Obligation for the same path FTR Options will only be available on a subset of paths 111

Overlapping Timeframes The Annual, Long-Term, and Monthly FTR Auctions are multi-period auctions with FTR products that can overlap across multiple timeframes FTR products can be On Peak FTRs, Off Peak FTRs and 24 Hour FTRs FTRs awarded in the Annual FTR Auction have a term of one year FTRs awarded in the Long-Term FTR Auctions have a term of one or three years. The various products are cleared simultaneously and the clearing prices of products which overlap are related 112

Multi-period FTR Auction - Example #1 Simple radial system A B Line AB On Peak Rating = 100 MW Line AB Off Peak Rating = 120 MW Auction Results FTR Bids Bid Price MW Cleared Clearing Price On Peak 130 MW $100/MW 100 MW $100/MW Off Peak 130 MW $ 95/MW 120 MW $ 95/MW 24 Hour (On Peak + Off Peak) 130 MW $180/MW 0 MW $195/MW 113

Multi-period FTR Auction - Example #2 Simple radial system A B Line AB On Peak Rating = 100 MW Line AB Off Peak Rating = 120 MW Auction FTR Bids Bid Price MW Cleared Clearing Price Results On Peak 90 MW $100/MW 90 MW $ 85/MW Off Peak 130 MW $ 95/MW 110 MW $ 95/MW 24 Hour (On Peak + Off Peak) 130 MW $180/MW 10 MW $180/MW 114

Multi-period FTR Auction - Example #3 Simple radial system A B Line AB On Peak Rating = 100 MW Line AB Off Peak Rating = 120 MW Auction FTR Bids Bid Price MW Cleared Clearing Price Results On Peak 90 MW $100/MW 0 MW $115/MW Off Peak 130 MW $ 95/MW 20 MW $ 95/MW 24 Hour (On Peak + Off Peak) 130 MW $210/MW 100 MW $210/MW 115

Multi-period FTR Auction - Example #4 Simple radial system A B Line AB On Peak Rating = 100 MW Line AB Off Peak Rating = 120 MW Auction FTR Bids Bid Price MW Cleared Clearing Price Results On Peak 90 MW $150/MW 70 MW $150/MW Off Peak 90 MW $ 95/MW 90 MW $ 20/MW 24 Hour (On Peak + Off Peak) 130 MW $170/MW 30 MW $170/MW 116

eftr eftr is an internet application that allows PJM Market Participants to participate in Annual ARR Allocation FTR Auctions FTR Secondary Market 117

Submitting Valid Auction Quotes Market Source Sink Class (on-peak, off-peak or 24 hour) Period Hedge (option or obligation) Trade (buy, sell or self-schedule for Round 1 of annual auction) Bid MW Bid Price ($/MW-three year for three year Long-Term FTR product or $/MW-year for yearly product or $/MW-month for monthly product or $/MW-quarter for quarterly product) 118

FTR Auction Credit Requirement FTR Auction participants must establish an Auction Credit Limit prior to bidding into auction Credit Requirement for a participant s bids may not exceed Credit Limit Credit Requirement for individual FTR bids is price of the FTR bid minus estimate of revenue from the FTR Participant s Credit Requirement is sum of Credit Requirement for each individual FTR bid offset by total value of Participant s ARRs 119

FTR Auction Credit Rules Credit requirements apply to All FTR auctions Use monthly weighted average of past three years (50%-30%- 20%) when calculating historical value Separate historic values for on-peak, off-peak and 24-hour FTRs Discount historical value by 10% when calculating credit requirements for FTR paths with positive expected value and add 10% for FTR paths with negative expected value Specific timetable for credit release No credit requirement for participants that self-schedule their ARRs into FTRs since ARR credits offset FTR costs in full 120

FTR Auction Credit Calculation Credit Requirement Calculation 1. Starts with a monthly credit calculation for each FTR Monthly Price minus discounted historical value for each month for each FTR 2. Within each month individual FTR credit numbers are added across all FTRs to result in 12 monthly subtotals for the account. For cleared FTRs only, negative individual FTR credit numbers will offset positive numbers within the same month. ARR credits in the account are subtracted from credit requirements each month. Monthly ARR value 3. Credit requirement is the sum of positive monthly subtotals 121

Additional Credit Requirements for Undiversified Portfolios FTR credit requirements for undiversified FTR auction bidding Undiversified Portfolio Definitions Flow Undiversified = the FTR Portfolio is net counterflow which means the total value of the portfolio is negative based on FTR auction clearing prices. Geographically Undiversified = The FTR portfolio is Flow Undiversified and the FTR portfolio has lower projected target allocations because of a single transmission outage. The FTR portfolio is the cumulative position for all current and future FTRs cleared in previous auctions and FTRs cleared in any current preliminary auction case. 122

Additional Credit Requirements for Undiversified Portfolios (cont) Diversification check performed after preliminary auction clearing Screen for undiversified portfolios (geographically and by flow) Additional collateral: 2 times absolute value of FTR auction-based value if flow undiversified 3 times absolute value of FTR auction-based value if flow and geographically undiversified PJM issues demand for additional credit as required by diversification test Participants bids are removed from auction if demand not satisfied by 4:00 pm next day 123

FTR Credit Example Historical LMPs and Hours HISTORICAL LMP NODE JUN JUL AUG SEP OCT NOV DEC JAN FEB MAR APR MAY A $23 $25 $27 $23 $18 $56 $52 $49 $47 $35 $29 $25 B $36 $38 $40 $54 $49 $34 $30 $27 $25 $45 $42 $38 C $34 $36 $38 $34 $29 $23 $27 $25 $45 $44 $40 $36 D $14 $20 $24 $65 $60 $42 $31 $33 $29 $44 $26 $22 E $37 $40 $43 $37 $52 $24 $33 $31 $60 $56 $47 $42 F $67 $69 $71 $13 $8 $65 $61 $58 $56 $23 $73 $69 G $34 $36 $38 $26 $21 $45 $41 $38 $36 $32 $40 $36 H $3 $5 $7 $67 $62 $13 $9 $6 $4 $16 $9 $5 Assume On-Peak, Off-Peak, and 24-HR historical LMPs are the same for example. 124

FTR Credit Example 125

FTR Credit Example (cont) 126

Same-Path FTR Bids Calculates the highest possible credit requirement for bids placed on the same path For each set of same-path bids, the credit requirement for each possible outcome is determined and the outcome which produces the highest credit requirement is used to determine the bid credit requirement for the set of same-path bids The price which is determined to cause the highest potential credit requirement will be used for all bids at or above price for buy bids and at or below price for sell offers. 127

Example of Credit calculation for same characteristic bids Bid Credit Rule for Same-Path FTRs Bids (cont) Credit Requirements Individual Credit Requirements Same Path Total= $10,684,363 Highest possible credit requirement is at the $300 price so this price is used to determine credit requirement for all bids above $300 Total= $10,498,119 128

Summary The FTR Auctions maximize the quote based bid value of a set of simultaneous feasible FTRs awarded in each auction Annual FTR Auction revenues are distributed to ARR Holders in proportion to the economic value of the ARRs The Annual FTR Auction offers for sale the entire FTR capability of the transmission system minus approved Long-Term FTRs for the term of one year The Annual FTR Auction is a multi-product, multi-period, and multi-round auction 129

Summary (cont) In the Annual FTR Auction, ARR holders have the option to convert their ARRs into FTRs by Self- Scheduling FTRs this option must be selected in Round 1 The Long-Term FTR Auctions offer FTRs for one or three years after the current Annual FTR Auction where the residual capability after assumed modeled Self- Scheduled ARRs and already approved Long-Term FTRs is available The Monthly FTR Auctions offer for sale or purchase the residual FTR capability of the transmission system for the term of one month or one quarter. The Monthly FTR Auctions are multi-product, multiperiod, single round auctions FTR credit requirements apply to all FTR Auctions 130

Market Settlements www.pjm.com PJM 2012 131

Annual FTR Auction Settlements The Annual FTR Auction and corresponding ARRs will be settled for on a monthly basis over the course of the planning period for which the Annual FTRs are in effect. Since ARR ownership can change daily through ARR reassignment, PJM Settlements calculates: daily Annual FTR Auction revenues by dividing annual auction revenues by the number of days in the planning period daily ARR credits by dividing ARR Target Allocation by the number of days in the planning period 132

ARR Settlements (cont.) If sufficient revenues are collected from the Annual and Monthly FTR Auctions to satisfy ARR Target Allocations then, ARR Credits = ARR Target Allocation Excess auction revenues are used to fund any deficiencies in FTR Target Allocation payments If insufficient revenues are collected from the Annual, Long- Term, and Monthly FTR Auctions to satisfy ARR Target Allocations then, ARR Credits are prorated proportionately ARR deficiencies are funded from (1) any annual excess congestion charges remaining at the end of a planning period after fully funding all FTR target allocations for the planning period then (2) an uplift charge assessed to FTR holders on pro-rata basis according to total Target Allocations for all FTRs held at any time during the planning period 134

Long-Term FTR Auction Settlements The Long-Term FTR auctions are billed for in the monthly bill for which the FTRs were in effect. Revenues from the Long-Term FTR auctions are used to first fund any shortfall in ARR Target Allocations then FTR target allocations for the planning period in which the Long-Term FTR is in effect. 135

Monthly FTR Auction Settlements The monthly auctions are billed for in the monthly bill for which the FTRs were in effect. Revenues from the monthly auctions are used to first fund ARR Target Allocations then FTR Target Allocations 136

FTR Settlements FTR Target Allocation = (FTR MW ) * (Congestion Price FTR Sink Congestion Price FTR Source) FTR Target Allocation is equal to the FTR MW amount times the congestion price difference from the FTR sink point to the FTR source point Congestion Price based on the clearing prices from Day Ahead Market If Congestion Price FTR Sink < Congestion Price FTR Source the FTR is a liability if FTR defined as Obligation the FTR has zero value if defined as Option 137

FTR Settlements (cont.) If sufficient congestion charges are collected from the Day Ahead and Balancing Market to satisfy FTR Target Allocations then, FTR Credits = FTR Target Allocation Excess congestion charges are used to cover any deficiencies in FTR Target Allocations within month cover any deficiencies in FTR Target Allocations within planning period any remaining year-end excess covers any deficiencies in ARR Target Allocation from previous months within planning period any remaining year-end excess distributed to FTR participants pro-rata to total FTR Target Allocations If insufficient revenues are collected from the Day Ahead and Balancing Market to satisfy FTR Target Allocations then, FTR Credits are prorated proportionately pro-rata to FTR Target Allocations FTR Target Allocation deficiencies are funded from (1) excess congestion charges from current month and subsequent months then (2) an uplift charge assessed to FTR holders on pro-rata basis according to total Target Allocations for all FTRs held at any time during the planning period 138

ANNUAL FTR AUCTION REVENUE MONTHLY FTR AUCTION REVENUE DAY AHEAD MARKET CONGESTION CHARGES BALANCING MARKET CONGESTION CHARGES ARR & FTR Settlements SUM OF MONTHLY ARR TARGET ALLOCATIONS SUM OF MONTHLY FTR TARGET ALLOCATIONS YES ARE ARR TARGET ALLOCATIONS FULLY- FUNDED FOR MONTH? MONTHLY EXCESS ARE FTR TARGET ALLOCATIONS FULLY- FUNDED FOR MONTH? YES NO NO FUND ARRs PRO-RATA TO ARR TARGET ALLCOATION FUND FTRs PRO-RATA TO FTR TARGET ALLOCATION DISTRIBUTE EXCESS ACROSS PRIOR MONTHLY DEFICIENCIES MONTHLY DEFICIENCY MONTHLY DEFICIENCY MONTHLY EXCESS ANNUAL ARR DEFICIENCY BUCKET IF EXCESS EXISTS ANNUAL FTR DEFICIENCY BUCKET ANNUAL EXCESS ARR REVENUE AND CONGESTION CHARGE BUCKET IF EXCESS EXISTS YEARLY DEFICIENCY YEARLY DEFICIENCY DISTRIBUTED TO FTR PARTICPANTS PRO-RATA TO FTR TARGET ALLOCATION FUNDED BY RATIO SHARE OF TOTAL FTR TARGET ALLCOATIONS 139

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Annual ARR Allocation Example www.pjm.com PJM 2012 141

Annual Allocation Example Demonstrates the following.. How Market Participants request ARRs in Stage 1 How Market Participants request ARRs in Stage 2 How PJM tests all requests for feasibility How PJM approves and allocates ARRs to Market Participants in each Stage 142

ARR/FTR Market Timeline Annual Allocation Stage 1A and 1B Annual Allocation Stage 2 (3 Rounds) ARR Trading Annual FTR Auction (4 Rounds) 143

System Profiles E 240 MW Thermal Limit D Brighton Sundance A Legend Alta Park City B C Solitude Bus Transmission Line Load Generators 144

Market Participants Peak Load = 400 MW Historical Generation Assignment 200 MW from Sundance 280 MW from Solitude Network Transmission Service = 400 MW LSE B Load Serving Entities (LSEs) = 3 Independent Generators = 2 Peak Load = 350 Historical Generation Assignment 300 MW from Brighton LSE C Peak Load = 350 Historical Generation Assignment 300 MW from Brighton LSE D 120 MW from Solitude 120 MW from Solitude Network Transmission Service 350 MW Network Transmission Service 350 MW 145

Market Participants Park City Sells to Spot Market Load Serving Entities (LSEs) = 3 Independent Generators = 2 Bilateral with LSE D Firm Service for 70 MW from Bus A to Bus D Alta 146

Stage 1A and 1B ARR Requests Submitted Market Participant Peak Load Historical Generation Resource Stage 1 Requested ARRs LSE B 400 MW 200 MW from Sundance 280 MW from Solitude 200 MW from Sundance (Bus D) 200 MW from Solitude (Bus C) LSE C 350 MW 300 MW from Brighton 120 MW from Solitude 300 MW from Brighton (Bus E) 0 MW from Solitude (Bus C) LSE D 350 MW 300 MW from Brighton 120 MW from Solitude 300 MW from Brighton (Bus E) 50 MW from Solitude (Bus C) 147

Stage 1A and 1B ARR SFT Summary of Withdrawals and Injections in SFT Injections Withdrawals Ensures all subscribed ARRs are within the capability of the system Ensures that the Annual FTR Auction Revenue is enough to cover economic value of ARRs LSE B LSE C LSE D Brighton Solitude Sundance 400 MW 300 MW 350 MW 600 MW 250 MW 200 MW TOTAL 1050 MW 1050 MW 148

Stage 1A and 1B ARR SFT Under the Limit! Brighton 600 MW E 300 MW from E to C 300 MW from E to D Alta 406.7 A 193.3 Park City 240 MW Thermal Limit 400 MW B 103.3 C 200 MW from D to B D 200 MW 350 MW 303.4 96.6 146.6 300 MW 250 MW Sundance Solitude 200 MW from C to B 50 MW from C to D 149

Stage 1A and 1B - ARRs Requests Approved All requested ARRs are feasible and can be awarded Market Participant Peak Load Stage 1 Approved ARRs LSE B 400 MW 200 MW from Sundance (Bus D) 200 MW from Solitude (Bus C) LSE C 350 MW 300 MW from Brighton (Bus E) LSE D 350 MW 300 MW from Brighton (Bus E) 50 MW from Solitude (Bus C) 150

Stage 1 Allocation - Summary After Stage 1 Allocation.. LSE B and LSE D allocated ARR MWs up to Peak Load not eligible for additional requests in Stage 2 LSE C allocated ARR MWs of 300 MW with Peak Load of 350 MW Eligible to request up to 16.6 MW of ARRs in each round of Stage 2 (16.8 MW in round 1) Line E-D flow = 193.3 MW after Stage 1 allocation therefore 15.5 MW of Line E-D capability will be allocated in each round of Stage 2 (15.7 in round 1) (240 MW 193.3 MW) / 3 = 15.5 MW 151

Stage 2 Round MW Calculation Stage 2 available is 1/3 remaining after Stage 1 Exact Round percentage distribution Stage 2 Round 1= 33.34% Stage 2 Round 2= 33.33% Stage 2 Round 3= 33.33% Example for total of 50 MW available in Stage 2 Round 1 = 50*.3334= 16.67 MW Round 2 = 50*.3333= 16.665 MW Round 3 = 50*.3333= 16.665 MW Request allowed to be made only to the tenth of a MW Adjusted Round 1 =16.67 +.065 +.065= 16.8 MW Adjusted Round 2 = 16.665 -.065= 16.6 MW Adjusted Round 3 = 16.665 -.065= 16.6 MW 152

Stage 2 - ARR Requests Submitted ARR Source Requested ARRs in Stage 2 Round 1 Round 2 Round 3 Total Stage 2 ARRs LSE C Brighton (Bus E) 16.8 MW 16.6 MW 16.6 MW 50 MW Alta Alta (Bus A to Bus D) 23.4 MW 23.3 MW 23.3 MW 70 MW Pt-to-Pt customer Alta requests ARRs associated with firm reservation LSE C assumed to request Bus E as ARR source point in each round Stage 2 is a sequential three-round process. This example assumes same requests made in each round. 153

Stage 1 + Stage 2 (Round 1) ARR SFT Stage 1 Awarded ARRs Stage 2 (Round 1) Requested ARRs Injections Withdrawals Injections Withdrawals LSE B 400 MW LSE C 16.8 MW LSE C 300 MW Bus D 23.4 MW LSE D 350 MW Brighton 16.8 MW Brighton 600 MW Alta 23.4 MW Solitude Sundance 250 MW 200 MW Summary of Withdrawals and Injections in SFT 154

Stage 1 + Stage 2 (Round 1) ARR SFT Brighton Under the Limit! 616.8 MW E 316.8 MW from E to C 300 MW from E to D Alta 23.4 MW from A to D 409.4 A 23.4 MW 207.4 Park City 209 MW Round 1 Thermal Limit 400 MW B 116.4 316.8 MW C 200 MW from D to B D 200 MW 373.4 MW 316.4 83.6 150.4 250 MW Sundance Solitude 200 MW from C to B 50 MW from C to D 155

Stage 1 + Stage 2 (All Rounds) ARR SFT Stage 1 Awarded ARRs Stage 2 (All Rounds) Requested ARRs Injections Withdrawals Injections Withdrawals LSE B 400 MW LSE C 50 MW LSE C 300 MW Bus D 70 MW LSE D 350 MW Brighton 50 MW Brighton 600 MW Alta 70 MW Solitude 250 MW Sundance 200 MW Summary of Withdrawals and Injections in SFT 156

Brighton Under the Limit! 650 MW E 350 MW from E to C 300 MW from E to D Alta 70 MW from A to D Stage 1 + Stage 2 (All Rounds) ARR SFT 414.8 A 70 MW 235.2 Park City 240 MW Thermal Limit 400 MW B 142.6 350 MW C 200 MW from D to B D 200 MW 420 MW 342.3 57.7 157.7 250 MW Sundance Solitude 200 MW from C to B 50 MW from C to D 157

Stage 2 - ARRs Requests Approved All requested ARRs are feasible and can be awarded Market Participant Approved ARRs LSE C 50 MW from Brighton (Bus E) Alta 70 MW from Alta (Bus A) to Bus D (Firm Point-to-Point) 158

Final Approved ARRs Stage 1 Approved ARRs Stage 2 Approved ARRs LSE B 200 MW from Sundance (Bus D) 200 MW from Solitude (Bus C) LSE C 300 MW from Brighton (Bus E) 50 MW from Brighton (Bus E) LSE D 300 MW from Brighton (Bus E) 50 MW from Solitude (Bus C) Alta 70 MW from Alta (Bus A) to Bus D (Firm Point-to-Point) 159

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Annual FTR Auction Example www.pjm.com PJM 2012 161

Annual FTR Auction Example Demonstrates the following.. A Four Round Auction How Market Participants enter bids and offers How Market Participants self-schedule FTRs How PJM clears each Auction Round and awards FTRs How PJM calculates Auction Revenue Right Target Allocations after each round 162

Results from Annual ARR Allocation Market Participant Approved ARRs ARRs are awarded to Participants in Annual ARR Allocation LSE B 200 MW from Sundance (Bus D) 200 MW from Solitude (Bus C) LSE C 350 MW from Brighton (Bus E) LSE D 300 MW from Brighton (Bus E) 50 MW from Solitude (Bus C) Alta 70 MW from Alta (Bus A) to Bus D (Firm Point-to-Point) 163

Market Participants bid for FTRs in Annual FTR Auction 164

Annual FTR Auction - Round 1 First 25% of the feasible system capability is awarded in Round 1 FTRs that are self-scheduled must be submitted in Round 1 Round 1 166

Round 1- Quotes Entered FTR Path MW Bid Bid Price Round 1 Bids LSE B No Bid LSE C Bus E-to-Bus C 300.0 MW $ 100/MW LSE D Bus E-to-Bus D 300.0 MW $ 100/MW Alta No Bid Round 1 Self Scheduled FTRs Round 1 Offers FTR Path MW Price LSE D Bus C-to-Bus D 50.0 MW Price Taker No Offers 167

Round 1 Market Clears Power Flows & Nodal Prices $0.0 E D $149.71 60 MW 12.5 MW 180.8 MW 33 MW 180.8 MW E-to-C FTR bid awarded in Round 1 A 121 MW $34.89 88 MW 88 MW 180.8 MW 80 MW 12.5 MW C-to-D FTR self schedule awarded in Round 1 $81.92 B C $100.0 168

Round 1- FTRs Awarded Round 1 FTR Path MW Bid/Offer Price MWs Cleared Clearing Price Revenue LSE B No Bid LSE C E-to-C 300.0 MW $ 100/MW 180.8 MW $100.00/MW $ 18,080.00 LSE D E-to-D 300.0 MW $ 100/MW 0.0 MW $149.71/MW $ 0.00 LSE D C-to-D 12.5 MW Price Taker 12.5 MW $ 49.71/ MW $ 621.38 Alta No Bid Round 1 Total Auction Revenue = $18,701.38 169

Round 1 Calculate ARR Target Allocation Revenues are distributed to ARR holders in proportion to (but not to exceed) the economic value of the ARRs which is determined by following equation: ARR Target Allocation = (ARR MW ) * (LMP ARR Sink - LMP ARR Source ) (# of rounds) Round 1 Total Auction Revenue = $18,701.38 Round 1 Total Target Allocation =????????? 170

Round 1 - Target Allocation Round 1 ARR Holder ARR MW ARR Sink ARR Source ARR MW # of rounds LMP Sink LMP Source ARR Target Allocation LSE B 200 Bus B Bus D 200/4 $ 81.92 $149.71 -$ 3,389.50 LSE B 200 Bus B Bus C 200/4 $ 81.92 $100.00 -$ 904.00 LSE C 350 Bus C Bus E 350/4 $100.00 $ 0.00 $ 8,750.00 LSE D 300 Bus D Bus E 300/4 $149.71 $ 0.00 $11,228.25 LSE D 50 Bus D Bus C 50/4 $149.71 $100.00 $ 621.38 Alta 70 Bus D Bus A 70/4 $149.71 $ 34.89 $ 2,009.35 Round 1 Total Target Allocation = $18,315.45 171

Round 1 Summary Results Round 1 Total Auction Revenue = $18,701.38 >= Round 1 Total Target Allocation = $18,315.45 Round 1 Auction revenues are enough to satisfy Total ARR Target Allocations therefore ARR Credits = ARR Target Allocations Round 1 Total ARR Credits = $18,315.45 Round 1 Total Excess = $ 385.93 172

Round 1 - Auction Payments Round 1 Market Participant FTR Auction Payment ARR Credits Auction Payment - ARR Credit (1) LSE B $ 0.00 -$ 4,293.50 $ 4,293.50 LSE C $ 18,080.00 $ 8,750.00 $9,330.00 LSE D $ 621.38 $11,849.60 -$11,228.22 Alta $ 0.00 $2,009.35 -$2,009.35 TOTAL $18,701.38 $18,315.45 $385.93 (1) Positive values indicate payment net to PJM 173

Annual FTR Auction - Round 2 Second 25% of the feasible system capability is awarded in Round 2 Awarded FTRs from Round 1 are modeled as fixed injections in Round 2 25% of Self-Scheduled FTRs from Round 1 are modeled as fixed injections in Round 2 Round 2 174

Round 2- Quotes Entered Round 2 Bids LSE B FTR Path MW Bid Bid Price No Bid LSE C Bus E-to-Bus C 300.0 MW $ 100/MW LSE D Bus E-to-Bus D 300.0 MW $ 100/MW Alta No Bid Round 2 Offers No Offers 175

Round 2-Fixed Injections Awarded FTRs FTR Path Cleared MW Round LSE C Bus E-to-Bus C 180.8 MW Round 1 LSE D Bus C-to-Bus D 12.5 MW Round 1 Self-Scheduled FTRs FTR Path Cleared MW Round LSE D Bus C-to-Bus D 12.5 MW Round 1 176

Round 2 Market Clears $0.0 E Power Flows & Nodal Prices 120 MW D 25 MW $149.71 361.6 MW 67 MW 180.8 MW E-to-C FTR bid awarded in Round 1 180.8 MW E-to-C FTR bid awarded in Round 2 A 242 MW $34.89 175 MW $81.92 B 175 MW 361.6 MW C 162 MW 25 MW 12.5 MW C-to-D FTR self schedule awarded in Round 1 12.5 MW C-to-D FTR self schedule awarded in Round 2 $100.0 177

Round 2- FTRs Awarded Round 2 FTR Path MW Bid/Offer Price MWs Cleared Clearing Price Revenue LSE B No Bid LSE C E-to-C 300.0 MW $100.00/MW 180.8 MW $100.00/MW $ 18,080.00 LSE D E-to-D 300.0 MW $100.00/MW 0.0 MW $149.71/MW $ 0.00 LSE D C-to-D 12.5 MW Price Taker 12.5 MW $ 49.71/ MW $ 621.38 Alta No Bid Round 2 Total Auction Revenue = $18,701.38 178

Round 2 Calculate ARR Target Allocation Revenues are distributed to ARR holders in proportion to (but not to exceed) the economic value of the ARRs which is determined by following equation: ARR Target Allocation = (ARR MW ) * (LMP ARR Sink - LMP ARR Source ) (# of rounds) Round 2 Total Auction Revenue = $18,701.38 Round 2 Total Target Allocation =????????? 179

Round 2 - Target Allocation Round 2 ARR Holder ARR MW ARR Sink ARR Source ARR MW # of rounds LMP Sink LMP Source ARR Target Allocation LSE B 200 Bus B Bus D 200/4 $ 81.92 $149.71 -$ 3,389.50 LSE B 200 Bus B Bus C 200/4 $ 81.92 $100.00 -$ 904.00 LSE C 350 Bus C Bus E 300/4 $100.00 $ 0.00 $ 8,750.00 LSE D 300 Bus D Bus E 300/4 $149.71 $ 0.00 $11,228.25 LSE D 50 Bus D Bus C 50/4 $149.71 $100.00 $ 621.38 Alta 70 Bus D Bus A 70/4 $149.71 $ 34.89 $ 2,009.35 Round 2 Total Target Allocation = $18,315.45 180

Round 2 Summary Results Round 2 Total Auction Revenue = $18,701.38 >= Round 2 Total Target Allocation = $18,315.45 Round 2 Auction revenues are enough to satisfy Total ARR Target Allocations therefore ARR Credits = ARR Target Allocations Round 2 Total ARR Credits = $18,315.45 Round 2 Total Excess = $ 385.93 181

Round 2 - Auction Payments Round 2 Market Participant FTR Auction Payment ARR Credits Auction Payment - ARR Credit (1) LSE B $ 0.00 -$ 4,293.50 $ 4,293.50 LSE C $ 18,080.00 $ 8,750.00 $ 9,330.00 LSE D $ 621.38 $11,849.60 -$11,228.22 Alta $ 0.00 $2,009.35 -$2,009.35 TOTAL $18,701.38 $18,315.45 $385.93 (1) Positive values indicate payment net to PJM 182

Annual FTR Auction - Round 3 Third 25% of the feasible system capability is awarded in Round 3 Awarded FTRs from Round 1 and Round 2 are modeled as fixed injections in Round 3 25% of Self-Scheduled FTRs from Round 1 are modeled as fixed injections in Round 3 Round 3 183

Round 3 Quotes Entered Round 3 Bids LSE B FTR Path MW Bid Bid Price No Bid LSE C No Bid LSE D Bus E-to-Bus D 300.0 MW $ 200/MW Alta Bus A-to-Bus D 70.0 MW $ 100/MW Round 3 Offers FTR Path MW Offer Offer Price LSE C Bus E-to-Bus C 61.5 MW $ 100/MW 184

Round 3 Fixed Injections Awarded FTRs FTR Path Cleared MW Round LSE C Bus E-to-Bus C 180.8 MW Round 1 LSE D Bus C-to-Bus D 12.5 MW Round 1 LSE C Bus E-to-Bus C 180.8 MW Round 2 LSE D Bus C-to-Bus D 12.5 MW Round 2 Self-Scheduled FTRs FTR Path Cleared MW Round LSE D Bus C-to-Bus D 12.5 MW Round 1 185

Round 3 Market Clears $0.0 61.5 MW E Power Flows & Nodal Prices 180 MW D 199.3 MW $200.0 523.4 MW 180.8 MW E-to-C FTR bid awarded Round 1 180.8 MW E-to-C FTR bid awarded in Round 2 161.8 MW E-to-D FTR bid awarded Round 3 A 282 MW $46.60 $109.44 117 MW 165 MW 165 MW 361.6 MW B C 97 MW 99 MW $133.59 12.5 MW C-to-D FTR self schedule awarded in Round 1 12.5 MW C-to-D FTR self schedule awarded in Round 2 12.5 MW C-to-D FTR self scheduled awarded in Round 3 61.5 MW E-to-C FTR offer awarded in Round 3 186

Round 3 - FTRs Awarded Round 3 FTR Path MW Bid/Offer Price MWs Cleared Clearing Price Revenue LSE B No Bid LSE C E-to-C 61.5 MW $100.00/MW 61.5 MW $133.59/MW -$ 8,215.79 LSE D E-to-D 300.0 MW $200.00/MW 161.8 MW $200.00/MW $ 32,360.00 LSE D C-to-D 12.5 MW Price Taker 12.5 MW $ 66.40/MW $ 830.13 Alta A-to-D 70.0 MW $100.00/MW No Quotes Cleared $153.40/MW Round 3 Total Auction Revenue = $24,974.34 187

Round 3 Calculate ARR Target Allocation Revenues are distributed to ARR holders in proportion to (but not to exceed) the economic value of the ARRs which is determined by following equation: ARR Target Allocation = (ARR MW ) * (LMP ARR Sink - LMP ARR Source ) (# of rounds) Round 3 Total Auction Revenue = $24,974.34 Round 3 Total Target Allocation =????????? 188

Round 3 - Target Allocation Round 3 ARR Holder ARR MW ARR Sink ARR Source ARR MW # of rounds LMP Sink LMP Source ARR Target Allocation LSE B 200 Bus B Bus D 200/4 $ 109.44 $200.00 -$ 4,528.00 LSE B 200 Bus B Bus C 200/4 $ 109.44 $133.59 -$ 1,207.50 LSE C 350 Bus C Bus E 350/4 $133.59 $ 0.00 $ 11,689.13 LSE D 300 Bus D Bus E 300/4 $200.00 $ 0.00 $ 15,000.00 LSE D 50 Bus D Bus C 50/4 $200.00 $133.59 $ 8 30.13 Alta 70 Bus D Bus A 70/4 $200.00 $ 46.60 $ 2,684.50 Round 3 Total Target Allocation = $ 24,468.26 189

Round 3 Summary Results Round 3 Total Auction Revenue = $24,974.34 >= Round 3 Total Target Allocation = $24,468.26 Round 3 Auction revenues are enough to satisfy Total ARR Target Allocations therefore ARR Credits = ARR Target Allocations Round 3 Total ARR Credits = $24,468.26 Round 3 Total Excess = $ 506.08 190

Round 3 - Auction Payments Round 3 Market Participant FTR Auction Payment ARR Credits Auction Payment - ARR Credit (1) LSE B $ 0.00 -$ 5,735.50 $ 5,735.50 LSE C -$ 8,215.79 $ 11,689.13-19,904.92 LSE D $ 33,190.13 $15,830.13 $ 17,360.00 Alta $ 0.00 $2,684.50 -$ 2,684.50 TOTAL $24,974.34 $24,468.26 $506.08 (1) Positive values indicate payment net to PJM 191

Annual FTR Auction - Round 4 Fourth 25% of the feasible system capability is awarded in Round 4 Awarded FTRs from Round 1, Round 2 and Round 3 are modeled as fixed injections in Round 4 25% of Self-Scheduled FTRs from Round 1 are modeled as fixed injections in Round 4 Round 4 192

Round 4 Quotes Entered Round 4 Bids LSE B LSE C FTR Path MW Bid Bid Price No Bid No Bid LSE D Bus E-to-Bus D 138.2 MW $ 500/MW Alta Bus A-to-Bus D 70.0 MW $ 500/MW Round 4 Offers No Offers 193

Round 4 Fixed Injections Awarded FTRs FTR Path Cleared MW Round LSE C Bus E-to-Bus C 180.8 MW Round 1 LSE D Bus C-to-Bus D 12.5 MW Round 1 LSE C Bus E-to-Bus C 180.8 MW Round 2 LSE D Bus C-to-Bus D 12.5 MW Round 2 LSE C Bus E-to-Bus C 61.5 MW Round 3 LSE D Bus E-to-Bus D 161.8 MW Round 3 LSE D Bus C-to-Bus D 12.5 MW Round 3 Self-Scheduled FTRs FTR Path Cleared MW Round LSE D Bus C-to-Bus D 12.5 MW Round 1 194

Round 4 Market Clears $0.0 61.5 MW E 240 MW Power Flows & Nodal Prices D $500.00 348.8 MW 590.4 MW 180.8 MW E-to-C FTR bid awarded in Round 1 180.8 MW E-to-C FTR bid awarded in Round 2 161.8 MW E-to-D FTR bid awarded in Round 3 67 MW E-to-D FTR bid awarded in Round 4 A 289 MW $116.51 70 MW 185 MW 70 MW A-to-D FTR bid awarded in Round 4 Bus A LMP 174 MW B $273.60 185 MW 361.6MW C 65 MW 111.5MW $333.97 12.5 MW C-to-D FTR self schedule awarded Round 1 12.5 MW C-to-D FTR self schedule awarded in Round 2 12.5 MW C-to-D FTR self schedule awarded in Round 3 61.5 MW E-to-C FTR offer awarded in Round 3 12.5 MW C-to-D FTR self schedule awarded in Round 4 195

Round 4 - FTRs Awarded Round 4 FTR Path MW Bid/Offer Price MWs Cleared Clearing Price Revenue LSE B LSE C No Bid No Bid LSE D E-to-D 138.2 MW $500.00/MW 67.0 MW $ 500.00/MW $ 33,500.00 LSE D C-to-D 12.5 MW Price Taker 12.5 MW $ 166.03/MW $ 2,075.38 Alta A-to-D 70.0 MW $500.00/MW 70.0 MW $ 383.49/MW $ 26,844.30 Round 4 Total Auction Revenue = $62,419.68 196

Round 4 Calculate ARR Target Allocation Revenues are distributed to ARR holders in proportion to (but not to exceed) the economic value of the ARRs which is determined by following equation: ARR Target Allocation = (ARR MW ) * (LMP ARR Sink - LMP ARR Source ) (# of rounds) Round 4 Total Auction Revenue = $62,419.68 Round 4 Total Target Allocation =????????? 197

Round 4 - Target Allocation Round 4 ARR Holder ARR MW ARR Sink ARR Source ARR MW # of rounds LMP Sink LMP Source ARR Target Allocation LSE B 200 Bus B Bus D 200/4 $ 273.60 $500.00 -$ 11,320.00 LSE B 200 Bus B Bus C 200/4 $ 273.60 $333.97 -$ 3,018.50 LSE C 350 Bus C Bus E 350/4 $333.97 $ 0.00 $ 29,222.38 LSE D 300 Bus D Bus E 300/4 $500.00 $ 0.00 $ 37,500.00 LSE D 50 Bus D Bus C 50/4 $500.00 $333.97 $ 2,075.38 Alta 70 Bus D Bus A 70/4 $500.00 $ 116.57 $ 6,711.08 Round 4 Total Target Allocation = $ 61,170.34 198

Round 4 Summary Results Round 4 Total Auction Revenue = $62,419.68 >= Round 4 Total Target Allocation = $61,170.34 Round 4 Auction revenues are enough to satisfy Total ARR Target Allocations therefore ARR Credits = ARR Target Allocations Round 4 Total ARR Credits = $61,170.34 Round 4 Total Excess = $ 1,249.35 199

Round 4 - Auction Payments Round 4 Market Participant FTR Auction Payment ARR Credits Auction Payment - ARR Credit (1) LSE B $ 0.00 -$ 14,338.50 $ 14,338.50 LSE C $ 0.00 $ 29,222.38 -$ 29,222.38 LSE D $ 35,575.38 $ 39,575.38 -$ 4,000.00 Alta $ 26,844.30 $ 6,711.08 $ 20,133.22 TOTAL $62,419.26 $61,170.34 $1,249.35 (1) Positive values indicate payment net to PJM 200

Annual FTR Auction Results Market Participant FTR ARR FTR Auction Payment ARR Credits Auction Payment - ARR Credit (1) LSE B 0 MW 0 MW 200 MW from D to B 200 MW from C to B $ 0.00 $ 0.00 -$ 22,627.00 -$ 6,034.00 $ 22,627.00 $ 6,034.00 LSE C 300 MW from E to C 350 MW from E to C $ 27,944.21 $ 58,411.51.00 -$ 30,467.30 LSE D 228.8MW from E-to-D 50 MW from C-to-D 300 MW from E-to-D 50 MW from C-to-D $ 65,860.00 $ 4,148.27 $ 74,956.50 $ 4,148.27 -$ 9,096.50 $ 0.00 Alta 70 MW from A-to-D 70 MW from A-to-D $ 26,844.30 $ 13,414.28 $ 13,430.02 TOTAL $124,796.78 $122,269.56 $ 2,527.22 (1) Positive values indicate payment net to PJM 201

Annual FTR Auction Settlement Market Participant FTR Auction Payment ARR Credits Annual Auction Payment -ARR Credit (1) LSE B $ 0.00 -$ 28,661.00 $ 28,661.00 LSE C $ 27,944.21 $ 58,411.51 -$ 30,467.30 LSE D $ 70,008.27 $ 79,104.77 -$ 9,096.50 Alta $ 26,844.30 $ 13,414.28 $ 13,430.02 TOTAL $124,796.78 $122,269.56 $ 2,527.22 (1) Positive values indicate payment net to PJM 202

Annual FTR Auction Settlement (cont) Round FTR Auction Revenue ARR Target Allocation Surplus/ Deficiency Round 1 $ 18,701.38 $ 18,315.45 $385.93 Round 2 $ 18,701.38 $ 18,315.45 $385.93 Round 3 $ 24,974.34 $ 24,468.26 $506.08 Round 4 $ 62,419.68 $ 61,170.34 $ 1,249.35 TOTAL $124,796.78 $122,269.56 $ 2,527.22 203

Annual FTR Auction Settlements (cont.) Total Auction Revenues = $124,796.78 Total ARR Credits = $122,269.56 Total Excess = $ 2,527.22 Excess revenue from the annual auction is used to fund any shortfall in FTR Target Allocations ARR credits prorated proportionately if there are insufficient annual auction revenues to cover all ARR credits ARR deficiencies may be funded from Long-Term and Monthly Auction revenues and annual Excess Congestion Charges 204

Annual Auction Example - Summary FTR Auction revenues are sufficient to cover total ARR Target Allocations because all ARRs were simultaneously feasible FTR Auction revenues exceed total ARR Target Allocation because allocated ARRs did not fully utilize the transmission system 25% of system capability auctioned in each round LSE D self-schedules 50 MW C-to-D FTR in Round 1 12.5 MW C-to-D FTR clears in each round and FTR payments equal ARR credits for this FTR 205

Annual Auction Summary (cont.) ARRs can be a liability (see LSE B ARR Credits) FTRs awarded in one round are modeled as fixed injections in the subsequent rounds FTRs awarded in one round can be offered for sale in subsequent rounds (LSE C sells E-to-C FTR Round 3) Alta receives 70 MW A-to-D FTR in Round 4 when clearing prices are highest. Alta s 70 MW A-to-D ARR credit does not completely offset Alta s payment for the FTR. 206

Appendix A: FTR Auction Clearing Mechanism www.pjm.com PJM 2012 207

Determining Winning Quotes Maximize bid-based value of FTR Auction Winning bids and offers are simultaneously feasible with prior committed FTRs 208

Determining Winning Quotes Download data from FTR market user database Solve linear program problem Check simultaneous feasibility of FTR auction solution Repeat Steps 2 & 3 Upload results to FTR market user interface 209

Step 1: Download Data from Database Uncompensated Parallel Flow Injections Transmission Outages Existing FTRs Facility Ratings FTR Quotes (Buy or Sell) PJM Network Model List of Contingencies Aggregate Price Definitions Optimization Engine 210

Step 2: Solve Linear Program Problem Objective: Determine highest valued combination of FTRs to be awarded in auction Calculate clearing prices differences in LMP at sink and source of FTR 211

Step 3: Check Simultaneous Feasibility Goal: Ensure that there are sufficient revenues for transmission congestion charges to satisfy all FTRs for the auction under expected conditions subject to transmission facility rating limits subject to transmission interface rating limits first contingency criteria 212

Step 5: Post FTR Auction Results Uncompensated Parallel Flow Injections Transmission Outage Schedules Existing FTRs Facility Ratings FTR Quotes (Buy or Sell) PJM Network Model List of Contingencies Aggregate Price Definitions FTR Auction Software FTRs Awarded in Auction FTRs Sold in Auction Nodal Prices Aggregate Prices Binding Constraints 213

Appendix A FTR Auction Clearing Mechanism Example www.pjm.com PJM 2012 214

The clearing mechanism of the FTR Auctions will maximize the quotebased value of the set of simultaneous feasible FTRs awarded in the auction, or each round of the auction The clearing prices will be calculated for all FTR Obligations at all buses, regardless of whether they are bought or sold in the auction. The clearing prices will be calculated for FTR Options for all valid FTR Option paths, regardless of whether they are bought or sold in the auction. FTR Auction Example Case 215

Firm Transmission & FTRs Market Participant Firm Network Firm Point-to Point FTR LSE B Peak Load 400 MW from 400 MW Brighton to LSE B LSE C Peak Load 150 MW from 350 MW Solitude to LSE C 200 MW from Brighton to LSE C LSE D Peak Load 220 MW from 350 MW Solitude to LSE D 130 MW from Sundance to LSE D Alta 70 MW 70 MW from A to D 216

Simultaneous Feasibility Test Ensures all subscribed transmission entitlements are within the capability of the system Ensures that the energy market will be revenue adequate Summary of Generation and Load in SFT LSE B LSE C LSE D Brighton Solitude Sundance Alta Generation 600 MW 370 MW 130 MW 70 MW Load 400 MW 350 MW 420 MW 217

Simultaneous Feasibility Test 130 MW from D to D Under the Limit! Brighton 600 MW E 400 MW from E to B 200 MW from E to C Alta 70 MW from A to D 370 70 MW A 230 Park City 240 MW Thermal Limit 400 MW 350 MW B 147 293 107 C D 370 MW 130 MW 420 MW 87 Sundance Solitude 220 MW from C to D 150 MW from C to C 218

PJM Auction Opens! 219

Auction Quotes FTR Buy Bids $5/MW Bid for 40 MW A-to-D FTR $4/MW Bid for 10 MW E-to-B FTR $4/MW Bid for 10 MW A-to-D FTR $4/MW Bid for 10 MW E-to-C FTR FTR Sell Offers $2/MW Sell Offer for 10 MW E-to-C FTR $6/MW Sell Offer for 10 MW A-to-D FTR NOTE: ALL BIDS IN THIS EXAMPLE ARE FOR FTR OBLIGATIONS 220

PJM Auction Closes! 221

Power Flows All Quotes Modeled E 10 MW 20 MW 248 MW 240 MW Thermal Limit 166 MW D 10 MW $6/MW Sell Offer for 10 MW A-to-D 50 MW FTR $4/MW Buy Bid for 10 MW E-to-B FTR $4/MW Buy Bid for 10 MW E-to-C FTR A $5/MW Buy Bid for 40 MW A-to-D FTR $4/MW Buy Bid for 10 MW A-to-D FTR 50 MW 362 MW 307 MW 103 MW 10 MW 10 MW 10 MW B C 83 MW 10 MW $2/MW Sell Offer for 10 MW E-to-C FTR 222

Selecting Winning Quotes (I) Path Buy Quotes MW Quote Quote Price Sensitivity Cost Effectiveness Sensitivity - portion of FTR that flows on Line E-D Cost Effectiveness - ratio of price to sensitivity Effect on Line E-D - MW times Sensitivity Effect on E-D Capability E-to-B 10 $4.00 0.2629 $16.21 2.6 A-to-D 40 $5.00 0.3685 $13.57 14.7 E-to-C 10 $4.00 0.3209 $12.46 3.2 A-to-D 10 $4.00 0.3685 $10.86 3.7 Sell Quotes E-to-C 10 $2.00-0.32092 -$6.07-3.2 A-to-D 10 $6.00-0.3685-16.28-3.7 223

Selecting Winning Quotes (II) Award bids by selecting from highest to lowest cost effectiveness, until all Line E-D capability is utilized. Compare sell offer cost effectiveness ratios (sorted highest to lowest) to cost of last marginal bid If cost effectiveness of sell offer is favorable to marginal bid cost effectiveness, sell offer is awarded. Additional bids are awarded to consume the FTR capability made available during Step 2. Repeat Steps 1, 2, and 3 until all capability is utilized. 224

What is the Commodity? Quote Buy 10 MW from Line E-B Buy 40 MW from Line A-D Sell 10 MW from Line E-C Buy 40 MW from Line A-D (20 MW remaining) Effect on Line E-D Remaining Capability on Line E-D Portion of Quote Awarded 2.6 7.4 MW 10 MW buy (10 MW buy quote) 7.4 0 MW 7.4/0.36849 = 20 MW buy (40 MW buy quote) -3.2 3.2 MW 10 MW sell (10 MW sell quote) 3.2 0 MW 3.2/0.36849 = 8 MW buy 8 MW + 20 MW = 28 MW buy (40 MW buy quote) 225

Clearing Price Calculation Source Sink Portion of FTR that flows on Line E-D Clearing Price Calculation A D 0.36849 A D is the Marginal FTR Path A B 0.15094 $5.00 * 0.15094/0.36849 = $2.05 A C 0.20895 $5.00 * 0.20895/0.36849 = $2.83 A E -0.11196 $5.00 * -0011196/0.36849 = -$1.52 E D 0.48045 $5.00 * 0.48045/0.36849 = $6.52 E C 0.32092 $5.00 * 0.32092/0.36849 = $4.35 E B 0.26290 $5.00 * 0.26290/0.36849 = $3.57 B C 0.05802 $5.00 * 0.05802/ 0.36849 = $0.79 B D 0.21755 $5.00 * 0.21755/0.36849 = $2.95 C D 0.15953 $5.00 * 0.15953/0.36849 = $2.16 226

Auction Results FTR Buy Bids $5/MW Bid for 40 MW A-to-D FTR $4/MW Bid for 10 MW E-to-B FTR $4/MW Bid for 10 MW A-to-D FTR $4/MW Bid for 10 MW E-to-C FTR FTR Sell Offers $2/MW Sell Offer for 10 MW E-to-C FTR $6/MW Sell Offer for 10 MW A-to-D FTR Quotes Cleared 28 MW @ $5.00/MW 10 MW @ $3.57/MW 0 MW 0 MW Quotes Cleared 10 MW @ $4.35/MW 0 MW FTR Auction Revenues (28 MW)($5.00/MW) +(10 MW)($3.57/MW) - (10 MW)($4.35/MW) = $132.20 227

$0.0 E 10 MW 10 MW $1.519 A Auction Results Clearing Prices by Path 240 MW 28 MW 360 MW 240 MW Thermal Limit 299 MW 10 MW 159 MW B 111 MW C 81 MW 10 MW D $3.567 $4.354 Sink A B C D E Source A 0 2.0481 2.8353 5-1.5191 B -2.0481 0 0.7872 2.9519-3.5672 C -2.8353-0.7872 0 2.1647-4.3544 D -5-2.9519-2.1647 0-6.5191 E 1.5191 3.5672 4.3544 6.5191 0 28 MW $6.519 228

Congestion Prices Brighton 600 MW $10/MWh 600 MW Alta 110 MW $14/MWh E $15 $10.44 A 110 MW 360 240 66 MW Constrained Day-Ahead Hour Park City 100 MW $15/MWh 240 MW Thermal Limit 300 MW 300 MW B 159 377 77 $21.14 Marginal Generators C $30 223 D 124 MW 300 MW $23.51 Sundance 200 MW $30/MWh Solitude 520 MW $30/MWh Total Congestion Charges =$9,771 229

Pre-Auction Congestion Credit Target Allocations FTR Source Sink Target Congestion Congestion Allocation Price Price 400 MW from E to B $10.44 $21.14 $4,280.00 200 MW from E to C $10.44 $23.51 $2,614.00 70 MW from A to D $15.00 $30.00 $1,050.00 220 MW from C to D $23.51 $30.00 $1,427.80 150 MW from C to C $23.51 $23.51 $ 0.00 130 MW from D to D $30.00 $30.00 $ 0.00 $9,372.00 230

Post-Auction Congestion Credit Target Allocations FTR Source Congestion Price Sink Congestion Price Target Allocation 400 MW from E to B $10.44 $21.14 $4,280.00 190 MW from E to C $10.44 $23.51 $2,483.30 70 MW from A to D $15.00 $30.00 $1,050.00 220 MW from C to D $23.51 $30.00 $1,427.80 150 MW from C to C $23.51 $23.51 $ 0.00 130 MW from D to D $30.00 $30.00 $ 0.00 28 MW from A to D $15.00 $30.00 $ 420.00 10 MW from E to B $10.44 $21.12 $ 106.80 $9,768.10 231

232

Appendix B: eftr - Market User Interfaces www.pjm.com PJM 2012 233

Portfolio Management 234

Messages 235

Reports 236

Quotes by Portfolio 237

Quotes by Participant 238

Market Results - Obligation Clearing Prices 239

Market Results - Option Prices 240

Market Results by Portfolio 241

Market Results by Participant 242

Market Results - Constraints 243

FTR Trading - Post FTRs 244

FTR Trading - Available FTRs 245

FTR Trading - Accepted FTRs 246

FTR Trading - Confirmed FTRs 247

FTR Position 248

FTR Credit Summary Total equals some of positive monthly values only 249

FTR Credit Detail Total for Cleared credit type is sum of positive and negative monthly cleared credit values. 250

ARR Requests - Stage 1 251

ARR Requests - Stage 1 252

ARR Requests - Stage 1 253

ARR Requests Stage 2 254