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 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. 23 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. their proportional impact on the binding constraints, the result would be a significant reduction in market participants’ ARRs. Table 13-25 shows the top 10 principal binding transmission constraints that limited the 2014 to 2015 Annual ARR Allocation. For the 2014 to 2015 ARR Stage 1A allocation, PJM was required to increase capability limits for several facilities in order to make the ARR allocation feasible.24 Waterford - Muskingum Flowgate MISO Breed - Wheatland Flowgate MISO Monroe - Bayshore Flowgate MISO Western Interface Interface PJM Loretto - Wilton Center Flowgate MISO Xxxxxxxxx - Xxxxxx Orchard Line Pepco Cedar Xxxxx - Xxxxxxx Line PSEG Xxxxxx - Electric Junction Flowgate MISO Marlton - New Freedom Line PSEG Roseland - Whippany Line PSEG PJM rules provide that when load switches between LSEs during the planning period, a proportional share of associated ARRs that sink into a given control or load aggregation zone is automatically reassigned to follow that load.25 ARR reassignment occurs daily only if the LSE losing load has ARRs with a net positive economic value to that control zone. An LSE gaining load in the same control zone is allocated a proportional share of positively valued ARRs within the control zone based on the shifted load. ARRs are reassigned to the nearest 0.001 MW and any MW of load may be reassigned multiple times over a planning period. Residual ARRs are also subject to the rules of ARR reassignment. This practice supports competition by ensuring that the offset to congestion follows load, thereby removing a barrier to competition among LSEs and, by ensuring that only ARRs with a positive value are reassigned,
Examples of Manual 6 in a sentence
This form requests details of derivatives held by an ADI or RFC in accordance with the 2008 System of National Accounts (SNA) and Balance of Payments Manual 6 (BPM) concept of derivatives as a financial instrument.
This category includes two- lane highways, multilane highways, and basic freeway segments as defined in the 2010 Highway Capacity Manual 6.
Tensas River National Wildlife Refuge lies within a physiographic region Agreement and associated issuance of known as the Mississippi Alluvial the ESP will not result in significant environmental, economic, social, historical or cultural impacts and is, therefore, categorically excluded from review under the National Environmental Policy Act (NEPA) of 1969, as amended, pursuant to 516 Department Manual 2, Appendix 1 and 516 Department Manual 6 Appendix 1.
BICSI CO-OSP: BICSI Customer-Owned Outside Plant Design Manual #6 9.5 Equipment Room Fittings 1.
Final figure is rounded from 501,153.6.78 USCIS Policy Manual, 6 USCIS–PM G at 8 (May 30, 2013) (‘‘However, for all TEA designations, USCIS must still ensure compliance with the statutory requirement that the proposed area designated by the state in fact has anproposed rule would not directly alter the states’ rights or obligations under the EB–5 program, and is fully consistent with the federal role in administration of immigration programs.
More Definitions of Manual 6
Manual 6. Financial Transmission Rights,” Revision 15 (October 10, 2013), pp. 21. 27 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> The introduction of residual zone pricing, while approved by PJM members, depends on a FERC order.
Manual 6. Financial Transmission Rights,” Revision 17 (June 1, 2016) p. 56.
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 13-6 presents the buy-bid, bid and cleared volume of the Monthly Balance of Planning Period FTR Auction, and the effective periods for the volume. The average monthly cleared volume for 2015 was 172,787.3 MW. The average monthly cleared volume for 2014 was 224,036.6 MW. Jan-15 Bid 971,818 380,246 165,248 332,579 1,849,891 Cleared 90,259 25,220 7,982 23,505 146,966 Feb-15 Bid 930,310 230,137 204,195 337,179 1,701,821 Cleared 103,322 16,683 14,472 33,276 167,753 Mar-15 Bid 926,146 248,594 275,292 234,112 1,684,143 Cleared 105,252 23,524 20,266 11,200 160,242 Apr-15 Bid 1,039,343 390,043 1,429,386 Cleared 113,418 26,621 140,039 May-15 Bid 817,152 817,152 Cleared 84,387 84,387 Jun-15 Bid 766,478 314,523 305,243 128,762 286,539 295,518 273,146 2,370,211 Cleared 81,472 22,796 20,096 8,887 22,091 23,222 16,792 195,356 Jul-15 Bid 904,856 349,043 208,322 291,464 304,176 283,784 2,341,645 Cleared 94,500 29,493 14,536 26,019 28,501 24,249 217,298 Aug-15 Bid 691,897 309,793 197,303 253,731 304,429 288,979 2,046,131 Cleared 80,734 22,612 16,510 16,943 25,396 21,717 183,912 Sep-15 Bid 1,153,687 364,094 306,346 138,961 343,682 322,103 2,628,872 Cleared 132,952 37,968 24,533 11,011 23,214 29,455 259,133 Figure 13-6 shows cleared auction volumes as a percent of the total FTR cleared volume by calendar months for June 2004 through September 2015, by type of auction. FTR volumes are included in the calendar month they are effective, with Long Term and Annual FTR auction volume spread equally to each month in the relevant planning period. This figure shows the share of FTRs purchased in each auction type by month. Over the course of the planning period an increasing number of Monthly Balance of Planning Period FTRs are purchased, making them a greater portion of active FTRs. When the Annual FTR Auction occurs, FTRs purchased in any previous Monthly Balance of Planning Period Auction, other than the current June auction, are no longer in effect, so there is a reduction in their share of total FTRs with an accompanying rise in the share of Annual FTRs.
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. 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). 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. 38. 6 See PJM. “Manual 6: Financial Transmission Rights,” Revision 15 (October 10, 2013), p. 55.
Manual 6. Financial Transmission Rights,” Revision 12 (July 1, 2009), pp. 54-55. 41 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.
Manual 6. Financial Transmission Rights” Revision 16 (June 1, 2014), p. 22. 10 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> The introduction of residual zone pricing, while approved by PJM members, depends on a FERC order. 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.11 PJM may also adjust the outages modeled, adjust line limits and account for potential closed loop interfaces to address expected revenue inadequacies. The simultaneous feasibility requirement is necessary to ensure that there are adequate 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 MW and in inverse proportion to their impact on binding constraints, except Stage 1A ARRs: Individual prorated MW = (Constraint capability) X (Individual requested MW / Total requested MW) X (1 / MW effect on line).12 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.