Manual 6. Financial Transmission Rights” Revision 15 (October 10, 2013), p. 22. • Stage 2. Stage 2 of the annual ARR allocation is a three-step procedure, with one-third of the remaining system capability allocated in each step of the process. Network transmission service customers can obtain ARRs from any hub, control zone, generator bus or interface pricing point to any part of their aggregate load in the control zone or load aggregation zone for which an ARR was not allocated in Stage 1A or Stage 1B. Firm, point-to-point transmission service customers can obtain ARRs consistent with their transmission service as in Stage 1A and Stage 1B. Prior to the start of the Stage 2 annual ARR allocation process, ARR holders can relinquish any portion of their ARRs resulting from the Stage 1A or Stage 1B allocation process, provided that all remaining outstanding ARRs are simultaneously feasible following the return of such ARRs.20 Participants may seek additional ARRs in the Stage 2 allocation. Effective for the 2015 to 2016 planning period, when residual zone pricing will be introduced, an ARR will default to sinking at the load settlement point, but the ARR holder may elect to sink their ARR at the physical zone instead.21 ARRs can also be traded between LSEs, but these trades must be made before the first round of the Annual FTR Auction. Traded ARRs are effective for the full 12-month planning period. When ARRs are allocated, all ARRs must be simultaneously feasible to ensure that the physical transmission system can support the approved set of ARRs. In making simultaneous feasibility determinations, PJM utilizes a power flow model of security-constrained dispatch that takes into account generation and transmission facility outages and is based on assumptions about the configuration and availability of transmission capability during the planning period.22 This simultaneous feasibility requirement is necessary to ensure that there are sufficient revenues from congestion charges to satisfy all resulting ARR obligations. If the requested set of ARRs is not simultaneously feasible, customers are allocated prorated shares in direct proportion to their requested
Manual 6. Financial Transmission Rights,” Revision 15 (October 10, 2013), pp. 31 and “IARRs for RTEP Upgrades Allocated for 2011/2012 Planning Period,” <xxxx://xxx.xxx.xxx/~/media/markets-ops/ftr/annual-arr-allocation/2011-2012/iarrs-rtep-upgrades- allocated-for-2011-12-planning-period.ashx>.
Manual 6. Financial Transmission Rights,” Revision 15 (October 10, 2013), pp. 55-56. simultaneously feasible, customers are allocated prorated shares in direct proportion to their requested MW and in inverse proportion to their impact on binding constraints: Equation 13‑1 Calculation of prorated ARRs Individual prorated MW = (Constraint capability) X (Individual requested MW / Total requested MW) X (1 / MW effect on line).22 The effect of an ARR request on a binding constraint is measured using the ARR’s power flow distribution factor. An ARR’s distribution factor is the percent of each requested MW of ARR that would have a power flow on the binding constraint. The PJM methodology prorates ARR requests in proportion to their MW value and the impact on the binding constraint. PJM’s method results in the prorating only of ARRs that cause the greatest flows on the binding constraint. Were all ARR requests prorated equally, regardless of their proportional impact on the binding constraints, the result would be a significant reduction in market participants’ ARRs. Table 13-21 shows the top 10 principal binding transmission constraints that limited the 2013 to 2014 Annual ARR Allocation. For the 2013 to 2014 ARR Stage 1A allocation, PJM was required to increase capability limits for several facilities in order to make the ARR allocation feasible.23 Table 13‑21 Top 10 principal binding transmission constraints limiting the Annual ARR Allocation: Planning period 2013 to 2014 Constraint Type Control Zone Xxxxxxx - Xxxxxx Flowgate MISO Silver Lake - Cherry Valley Line ComEd Electric Junction - Xxxxxx Line ComEd Oak Grove - Galesburg Flowgate MISO Waukegan-Zion Line ComEd Zion - Lakeview Line ComEd Lakeview Transformer MISO Zion Transformer ComEd Braidwood - East Frankfort Line ComEd Greystone - West Xxxxxxx Line JCPL 22 See the MMU Technical Reference for PJM Markets, at “Financial Transmission Rights and Auction Revenue Rights,” for an illustration explaining this calculation in greater detail.
Examples of Manual 6 in a sentence
Status: Not adopted.) • The MMU recommends that PJM improve transmission outage modeling in the FTR auction models, including the use of probabilistic outage 12 See “PJM Manual 6: Financial Transmission Rights,” Rev.
In an apparent effort to manage FTR revenues, PJM may adjust normal transmission limits (rather than the 38 See “PJM Manual 6: Financial Transmission Rights,” Rev.
There were 44,823 MW of ARRs associated with $339,500 of revenue that were reassigned in the receiving the asserted benefit of higher ARR value that 28 See “PJM Manual 6: Financial Transmission Rights,” Rev.
Network transmission service customers can obtain ARRs up to their share of zonal peak load, which is the highest daily peak load in the prior twelve month period increased by load growth projections, based on generation to load 18 “PJM Manual 6: Financial Transmission Rights,” Rev.
PJM can assume higher outage levels and PJM can decide to include additional constraints (closed loop interfaces) both of which reduce 29 See “PJM Manual 6: Financial Transmission Rights,” Rev.
More Definitions of Manual 6
Manual 6. Financial Transmission Rights” Revision 17 (June 1, 2016), p. 22.
Manual 6. Financial Transmission Rights,” Revision 17 (June 1, 2016), pp. 21. 12 See “Residual Zone Pricing,” PJM Presentation to the Members Committee (February 23, 2012) <xxxx://xxx.xxx.xxx/~/media/committees-groups/committees/mc/20120223/20120223-item- 03-residual-zone-pricing-presentation.ashx>.
Manual 6. Financial Transmission Rights” Revision 17 (June 1, 2016), p. 22. remain in effect for the planning period covered by the allocation. • Stage 2. Stage 2 of the annual ARR allocation is a three-step procedure, with one-third of the remaining system capability allocated in each step of the process. Network transmission service customers can obtain ARRs from any hub, control zone, generator bus or interface pricing point to any part of their aggregate load in the control zone or load aggregation zone for which an ARR was not allocated in Stage 1A or Stage 1B. Firm, point-to- point transmission service customers can obtain ARRs consistent with their transmission service as in Stage 1A and Stage 1B. Prior to the start of the Stage 2 annual ARR allocation process, ARR holders can relinquish any portion of their ARRs resulting from the Stage 1A or Stage 1B allocation process, provided that all remaining outstanding ARRs are simultaneously feasible following the return of such ARRs.11 Participants may seek additional ARRs in the Stage 2 allocation. Effective for the 2015 to 2016 planning period, when residual zone pricing was introduced, an ARR will default to sinking at the load settlement point, but the ARR holder may elect to sink their ARR at the physical zone instead.12 ARRs can also be traded between LSEs, but these trades must be made before the first round of the Annual FTR Auction. Traded ARRs are effective for the full 12-month planning period. When ARRs are allocated, all ARRs must be simultaneously feasible to ensure that the physical transmission system can support the approved set of ARRs. In making simultaneous feasibility determinations, PJM utilizes a power flow model of security-constrained dispatch that takes into account generation and transmission facility outages and is based on assumptions about the configuration and availability of transmission capability during the planning period.13 PJM may also adjust the outages modeled, adjust line limits and account for potential closed loop interfaces
Manual 6. Financial Transmission Rights,” Revision 16 (June 1, 2014), p22. the modeled capacity limits on 84 facilities, 24 of which were internal to PJM, a total of 6,271 MW.18 Figure 13-2 shows the predicted and estimated impact of Stage 1A infeasibilities on funding for the 2012 to 2013 through 2014 to 2015 planning periods, as well as the predicted impact on funding for the 2015 to 2016 planning period. The predicted funding is based on the infeasible ARR MW and the nodal price of the source and sink in the Annual FTR Auction. The estimated funding is calculated assuming every infeasible ARR MW is self scheduled, and uses the hourly congestion LMP values. In the 2014 to 2015 planning period Stage 1A ARR infeasibilities accounted for $105.9 million in over allocation. Figure 13-2 Stage 1A Infeasibility Funding Impact Predicted Estimated $300 $250 Funding Impact (Millions) $200 $150 $100 $50 $- 12/13 13/14 14/15 15/16 Figure 13-3 shows a map of over allocated ARR source points in Stage 1A, regardless of reason, for the 2013 to 2014 through 2015 to 2016 planning period. The year indicated for each source point is the latest year that source was announced as over allocated in the Stage 1A process. Generators retired as of the 2015 to 2016 planning period are indicated by a square marker to show Stage 1A source points that are no longer in service for the most recent Stage 1A allocation period. 18 PJM 2015/2016 Stage 1A Over allocation notice, PJM FTRs, <xxxx://xxx.xxx.xxx/~/media/ markets-ops/ftr/annual-arr-allocation/2015-2016/2015-2016-stage-1a-over-allocation-notice. ashx> (March 5, 2015). Figure 13-3 Overallocated Stage 1A ARR source points Revenue ARRs are allocated to qualifying customers rather than sold, so there is no ARR revenue comparable to the revenue that results from the FTR auctions.
Manual 6. Financial Transmission Rights,” Revision 15 (October 10, 2013,) p. 56. 12 See PJM. “Manual 6: Financial Transmission Rights,” Revision 15 (October 10, 2013,) p. 56. Table 13‑5 Monthly Balance of Planning Period FTR Auction market volume: 2015 Monthly Auction Type Trade Type Bid and Requested Count Bid and Requested Volume (MW) Cleared Volume (MW) Cleared Volume Uncleared Volume (MW) Uncleared Volume Jan-15 Obligations Buy bids 252,024 1,586,427 144,179 9.1% 1,442,248 90.9% Sell offers 99,255 247,626 61,026 24.6% 186,600 75.4% Options Buy bids 10,732 263,464 2,787 1.1% 260,678 98.9% Sell offers 2,886 15,735 4,571 29.1% 11,164 70.9% Feb-15 Obligations Buy bids 266,009 1,417,759 161,646 11.4% 1,256,112 88.6% Sell offers 96,236 237,844 51,752 21.8% 186,091 78.2% Options Buy bids 12,280 284,062 6,106 2.1% 277,956 97.9% Sell offers 3,281 16,999 5,332 31.4% 11,667 68.6% Mar-15 Obligations Buy bids 254,361 1,467,192 151,571 10.3% 1,315,621 89.7% Sell offers 97,054 259,360 54,239 20.9% 205,121 79.1% Options Buy bids 7,894 216,952 8,671 4.0% 208,281 96.0% Sell offers 4,158 28,822 8,783 30.5% 20,039 69.5% Apr-15 Obligations Buy bids 195,242 1,239,939 133,675 10.8% 1,106,263 89.2% Sell offers 67,401 211,198 53,998 25.6% 157,200 74.4% Options Buy bids 6,529 189,448 6,364 3.4% 183,084 96.6% Sell offers 3,049 23,932 7,442 31.1% 16,490 68.9% May-15 Obligations Buy bids 118,504 696,460 81,864 11.8% 614,596 88.2% Sell offers 35,828 104,822 36,911 35.2% 67,910 64.8% Options Buy bids 3,709 120,692 2,524 2.1% 118,169 97.9% Sell offers 1,366 12,379 4,778 38.6% 7,600 61.4% Jun-15 Obligations Buy bids 384,766 2,017,412 187,357 9.3% 1,830,054 90.7% Sell offers 180,141 553,702 102,726 18.6% 450,976 81.4% Options Buy bids 12,429 352,799 7,999 2.3% 344,800 97.7% Sell offers 11,041 57,100 15,172 26.6% 41,928 73.4% Jul-15 Obligations Buy bids 427,398 1,909,109 208,278 10.9% 1,700,831 89.1% Sell offers 185,213 575,921 111,179 19.3% 464,742 80.7% Options Buy bids 16,004 432,537 9,019 2.1% 423,517 97.9% Sell offers 14,202 52,274 15,790 30.2% 36,483 69.8% Aug-15 Obligations Buy bids 379,565 1,624,183 174,941 10.8% 1,449,242 89.2% Sell offers 147,217 405,601 92,842 22.9% 312,759 77.1% Options Buy bids 14,473 421,949 8,971 2.1% 412,978 97.9% Sell offers 12,307 46,856 12,875 27.5% 33,981 72.5% Sep-15 Obligations Buy bids 416,971 2,241,148 249,881 11.1% 1,991,267 88.9% Sell offers 146,522 420,845 86,461 20.5% 334,385 79.5% Options Buy bids 12,489 387,724 9,252 2.4% 378,472 97.6% Sell offers 11...
Manual 6. Financial Transmission Rights” Revision 16 (June 1, 2014), p. 56. • The MMU recommends that PJM eliminate portfolio netting to eliminate cross subsidies among FTR marketplace participants. (Priority: High. First reported 2012. Status: Not adopted. Pending before FERC.) • The MMU recommends that PJM eliminate subsidies to counter flow FTRs by applying the payout ratio to counter flow FTRs in the same way the payout ratio is applied to prevailing flow FTRs. (Priority: High. First reported 2012. Status: Not adopted.) • The MMU recommends that PJM eliminate geographic cross subsidies. (Priority: High. First reported 2013. Status: Not adopted.) • The MMU recommends that PJM improve transmission outage modeling in the FTR auction models. (Priority: Low. First reported 2013. Status: Adopted partially, 14/15 planning period.) • The MMU recommends that PJM reduce FTR sales on paths with persistent overallocation of FTRs including clear rules for what defines persistent overallocation and how the reduction will be applied. (Priority: High. First reported 2013. Status: Adopted partially, 14/15 planning period.) • The MMU recommends that PJM implement a seasonal ARR and FTR allocation system to better represent outages. (Priority: Medium. First reported 2013. Status: Not adopted.) • The MMU recommends that the basis for the Stage 1A assignments be reviewed and made explicit, that the role of out of date generation to load paths be reviewed and that the building of the transmission capability required to provide all defined Stage 1A allocations be reviewed. (Priority: High. First reported 2013. Status: Not adopted. Pending before FERC.) • The MMU recommends that PJM apply the FTR forfeiture rule to up to congestion transactions consistent with the application of the FTR forfeiture rule to increment offers and decrement bids. (Priority: High. First reported 2013. Status: Not adopted. Pending before FERC.) • The MMU recommends that PJM examine the mechanism by which self scheduled FTRs are allocated when load switching among LSEs occurs throughout the planning period. (Priority: Low. First reported 2011. Status: Not adopted.)
Manual 6. Financial Transmission Rights,” Revision 16 (June 1, 2014), pp. 31 and “IARRs for RTEP Upgrades Allocated for 2011/2012 Planning Period,” <xxxx://xxx.xxx.xxx/~/media/ markets-ops/ftr/annual-arr-allocation/2011-2012/iarrs-rtep-upgrades-allocated-for-2011-12- planning-period.ashx>. 9 See the 2006 State of the Market Report (March 8, 2007) for the rules of the annual ARR allocation process for the 2006 to 2007 and prior planning periods.