Manual 6 definition
Manual 6. Financial Transmission Rights,” Revision 16 (June 1, 2014), pp. 21. 10 See “Residual Zone Pricing,” PJM Presentation to the Members Committee (February 23, 2012) <▇▇▇▇://▇▇▇.▇▇▇.▇▇▇/~/media/ 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. For the entire 2014 to 2015 and 2015 to 2016 planning periods, FTR revenue adequacy was over 100 percent. Not every month was revenue adequate, but there was excess revenue from other months to make each month revenue adequate. The last time there were four months of consecutive funding of 100 percent or more was in the 2009 to 2010 planning period. This high level of revenue adequacy was primarily due to actions taken by PJM to address prior low levels of revenue adequacy. PJM’s actions included PJM’s arbitrary assumption of higher outage levels and PJM’s decision to 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. 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,” <▇▇▇▇://▇▇▇.▇▇▇.▇▇▇/~/media/markets-ops/ftr/annual-arr-allocation/2011-2012/iarrs-rtep-upgrades- allocated-for-2011-12-planning-period.ashx>.
Examples of Manual 6 in a sentence
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.
Such notice shall include the Special Procedure/Technique(s) at issue and the reasons for the proposal, including how the Special Procedures/Technique(s) meets, or no longer meets, the definition outlined in Classification Manual 6.
Status: Not adopted.) 12 See “PJM Manual 6: Financial Transmission Rights,” Rev.
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This Agreement implements the objectives of Director's Order 6, and Reference Manual 6, which encourage collaborative programs created in partnership with other agencies and institutions to achieve common goals in interpretation and education.
More Definitions of Manual 6
Manual 6. Financial Transmission Rights,” Revision 16 (June 1, 2014) p. 56.
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) <▇▇▇▇://▇▇▇.▇▇▇.▇▇▇/~/media/committees-groups/committees/mc/20120223/20120223-item- 03-residual-zone-pricing-presentation.ashx>.
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, <▇▇▇▇://▇▇▇.▇▇▇.▇▇▇/~/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 16 (June 1, 2014), p. 56. reported 2012. Status: Not adopted. Pending before FERC.) the payout ratio is applied to prevailing flow FTRs. (Priority: High. First reported 2012. Status: Not adopted.) Adopted partially, 14/15 planning period.) overallocation and how the reduction will be applied. (Priority: High. First reported 2013. Status: Adopted partially, 14/15 planning period.) reported 2013. Status: Not adopted.) 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.) forfeiture rule to increment offers and decrement bids. (Priority: High. First reported 2013. Status: Not adopted. Pending before FERC.) throughout the planning period. (Priority: Low. First reported 2011. Status: Not adopted.)
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 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. 38. For the Annual FTR Auction, known transmission outages that are expected to last for two months or more may be included in the model, while known outages of five days or more may be included in the model for the Monthly Balance of Planning Period FTR Auctions as well as any outages of a shorter duration that PJM determines would cause FTR revenue inadequacy if not modeled.18 The full list of outages selected is publicly posted, but the process by which these outages are selected is not fully explained and PJM exercises significant discretion in selecting outages to accomplish FTR revenue adequacy goals. The auction process does not account for the fact that significant transmission outages, which have not been provided to PJM by transmission owners prior to the auction date, will occur during the periods covered by the auctions. Such transmission outages may or may not be planned in advance or may be emergency outages. In addition, it is difficult to model in an annual auction two outages of similar significance and similar duration in different areas which do not overlap in time. The choice of which to model may have significant distributional consequences. The fact that outages are modeled at significantly lower than historical levels results in selling too many FTRs which creates downward pressure on revenues paid to each FTR. To address this issue, the MMU has recommended that PJM use probabilistic outage modeling and seasonal ARR/FTR markets to better align the supply of ARRs and FTRs with actual system capabilities.