• Request effective 12/12/23, for 25/26 BRA/DY
• Except DR testing charge provisions - request effective for 24/25 DY
• Companion filing ER24-98; revisions in this proceeding and that proceeding J&R on their own, but prefer acceptance together; encourage acceptance of both filings concurrently on requested timeframe
• "Particularly urges" timely commission action on this filing due to timing of implementation of accreditation/risk modeling changes

• Resource adequacy modeling and accreditation changes
• Marginal Accreditation for all resource types; Evaluates capacity capability of each resource individually
• Creates single fungible capacity product
• ELCC Classes for Unlimited Resources -  Nuclear Class, Coal Class, Gas Combined Cycle Class, Gas Combustion Turbine Class, Gas Combined Cycle Dual Fuel Class, Gas Combustion, Turbine Dual Fuel Class, Diesel Utility Class, Steam Class, and Other Unlimited Resource Class.
• Dual fuel class -  resource must be capable of “start[ing] and operat[ing] independently on an alternate, onsite fuel source up to its maximum capacity level during the winter season of the applicable Delivery Year in which it is providing capacity, and capable of operating on the alternate fuel for two 16-hour periods over two consecutive days at its maximum capacity level.”75
• ELCC analysis
• Hourly model testing resource performance under range of system conditions/modeled scenarios
• Range of conditions/modeled scenarios driven by load and resource uncertainty; uncertainty dictated by weather impacts based on historic conditions
• Modeled scenarios assigned probability
• For each hourly interval
• Compare expected hourly load levels (based on historical weather)” with the expected output of the “expected future resource mix” for each hour to “identify the relative marginal resource adequacy value of each individual ELCC Class compared to an Unlimited Resource with no outages.

• Hourly simulated dispatch for Limited Duration, Combination and Demand Resources
  • two general principles: (1) “[l]ess available resources are dispatched after the more available resources to maximize the system reliability benefit;” and (2) there is “variability of resources within some ELCC Classes.”98
  • Demand resources - only during seasonal performance window

• Portfolio EUE set based on EUE at .1 LOLE
• ELCC Class Rating set as “ratio of the expected unserved energy improvement resulting from adding an incremental quantity of the subject ELCC Class to the expected unserved energy improvement resulting from adding an incremental quantity of an Unlimited Resource with no outages, where expected unserved energy improvement is calculated relative to the Portfolio EUE for the Delivery Year.”
• Resource Accredited UCAP capped at  lesser of the resource’s Capacity Interconnection Right or the product of” the resource’s Effective Nameplate Capacity, its ELCC Class Rating, and its resource-specific performance adjustment.

• Variable resources
  • summer period (June through October) output cap be set at the “greater or” the resource’s Capacity Interconnection Rights or the resource’s “transitional system capacity.
  • Winter period (November through May) capped at “assessed deliverability, as defined in the PJM Manuals.”118
    • Modifies from "winter deliverability" which does not consider light load deliverability
• Demand Resources -  product of: the resource’s Nominated Value, the determination of which will continue to be governed by RAA, Schedule 6, sections I and K, and its ELCC Class Rating
  • No resource performance adjustment; lack of continuity in end use customers making up demand resources
• Resource Performance Adjustment - metric consisting of the weighted average hourly output of the resource in the ELCC model”
  • “(i) the weights correspond to the modeled probability of losing load in such hour
  • (ii) the expected hourly output is based on the resource’s modeled output during the same hour on days since June 1st, 2012 identified as having similar weather from an RTO-perspective.
  • ratio of such metric to the average (weighted by the Effective Nameplate Capacity in the case of Variable and Limited Duration Resources and installed capacity in the case of Unlimited Resources) of such metrics for all units in the applicable Variable Resource ELCC Class or applicable Unlimited Resource ELCC Class.”

• IRM/FPR adjustments
• Pool wide average accredited UCAP factor replaces 1-pool wide average EFORd in calculation of FPR
• FPR = (1+IRM)*Pool Wide Average Accredited UCAP factor
• CETO study modified to include new ELCC/RRS model
• CETO studies solve for a megawatt “amount of electric energy that a given area must be able to import in order to satisfy a normalized expected unserved energy for the area that is equal to forty percent of the normalized expected unserved energy for the RTO when at the annual reliability criteria
• Equivalent to current 1-in-25 LOLE requirement

• Binding notice of intent to offer for Planned Generation resources with no must offer requirement
• require all Capacity Market Sellers of any Planned Generation Capacity Resource to provide a binding notice of intent if such resource will be offered into in the relevant RPM Auction before the auction parameters are posted.190
• Prior to 12/1 prior to BRA
• Allows PJM to model in ELCC/RRS model
• Planned Generation Capacity Resources that are the subject of such binding notice of intent would then be required to be offered into the applicable RPM Auction
• Conversely, Planned Generation Capacity Resources that are not the subject of a binding  notice of intent to participate would not be allowed to be offered as capacity into the relevant RPM Auction.

• for any Planned Generation Capacity Resource that is associated with a notice of intent to offer, but is not offered into the auction, such resource will not be allowed to be offered in each of the subsequent Incremental Auctions associated with that Delivery Year.197
• Existing Generation Capacity Resources that are not subject to the capacity must offer requirement would not be subject to this requirement

• Enhancements to capacity testing
• (1) adding a requirement for such resources to physically perform a capability test in both the winter and summer seasons
• (2) assessing any testing shortfalls, in the form of capacity test failure charges, for each day of the season by comparing the seasonal test value against the resource’s daily committed installed capacity, rather than the average seasonal committed installed capacity
• (3) creating a new test, referred to as the Generator Operation Test, to test resource capability and operating parameter accuracy prior to periods of the year where PJM may experience extreme weather conditions; and

• Up to two PJM-initiated tests of a generator’s availability status, per season every Delivery Year
• timing of the tests and re-tests are subject to PJM’s dispatch discretion, as the goal is to issue the test during system conditions that are directionally close to those faced during a reliability event.228
• language is intentionally crafted in a manner that would allow PJM to conduct operational tests with an element of surprise.
• unit will be considered to have passed its test if it is synchronized to the grid within the start-up times specified in the schedule that PJM tests the unit on and operates for its minimum run time.
• Can be tested on any submitted schedule; allows for test on schedules with flexible operating parameters
• Failure results in retest by PJM, at its discretion, until resource demonstrates it can operate consistent with operating parameters
• Units will receive makewhole payments for costs associated for initial tests; however, units are not eligible to be made whole for PJM-initiated re-tests following a failed test
• If the retest is also failed, regardless of the reason, a Generation Capacity Resource Operational Test Failure Charge will apply from the point at which the Generation Capacity Resource failed the re-test until it can successfully synchronize to the grid after such a failed test, regardless of whether the retest

• (4) conforming the testing requirements for Demand Resources.211
• Conforming
• if a Demand Resource is not dispatched for a Load Management event in a Delivery Year and assessed for performance during Performance Assessment Intervals,246 then the resource will be tested, at a date and time to be determined by PJM, for a two-hour period during the relevant Delivery Year
• Capacity Market Seller may elect to utilize performance data from a Load Management event in the Delivery Year that was not assessed for performance during Performance Assessment Intervals to be considered in the Demand Resource test requirement, as long as the event is at least 30 minutes of a clock hour.248

• Reduction in annual stop loss to 1.5 x BRA Clearing Price x 365
• FRR penalty changes/transition
• Align FRR Insufficiency and Deficiency Charges
• PJM proposes to set the deficiency and insufficiency charge rates for FRR Entities at the price-level corresponding to Point 1 on the LDA VRR curve where the FRR obligation exists
• Beginning 26/27 DY greater of gross CONE or 1.75 times net CONE
• Transition options
• available to FRR Entities that in the midst of a minimum five-year commitment of the FRR election, is the opportunity to re-join the RPM beginning with the 2025/2026 Delivery Year.
• Minimum 5 year commitment period
• must provide written notice of the termination of its election of the FRR Alternative at least two months prior to the Base Residual Auction through the 2028/2029 Delivery Year
• PJM proposes to suspend any potential insufficiency charges through the end of the 2028/2029 Delivery Year.
• Once a Delivery Year starts, an FRR Entity will continue to be assessed a deficiency charge if an FRR Entity still has not secured sufficient capacity during the actual Delivery Year.289

• Request effective 12/12/2023
• Eligibility of performance payments and associated balancing ratio adjustment severable from rest of filing
• MSOC reform
• Capacity Market Sellers may include a CPQR value where its risk model, along with supporting documentation, has been “review[ed] by an independent third party entity with experience in evaluating capacity performance insurance policies to confirm that the proposed valuation of risk is consistent with actuarial practices in the industry.
• Such as consultants who evaluate capacity performance insurance or an insurance carrier that issues capacity performance insurance policies,
• not proposing any changes to existing review and approval process for a unit-specific CPQR…. all CPQR values, including under this alternative approach, must continue to be reviewed by both the Market Monitor and PJM and accepted by PJM as is currently the case.
• standardized methodology that can be used to calculate a unit-specific Capacity Performance Quantifiable Risk
• unit-specific CPQR
• request PJM to calculate their unit-specific risk cost consistent with the formula specified in the proposed Tariff.
• equal to the estimated cost of managing the risks of Non-Performance Charges multiplied by the annual total net Non-Performance Charges for the resource “based on a probabilistic analysis conducted by the Office of the Interconnection that models the resource’s performance under a range of simulated system conditions to measure the distribution of potential annual total net over- and underperformance of the resource.”
• such Sell Offers from Capacity Market Sellers that are deemed to have market power would still be reviewed by the Market Monitor and approved by PJM.31
• PJM CPQR Calculation
• would yield a distribution of performance during simulated Performance Assessment Intervals, as well as other parameters, such as Balancing Ratio, necessary to assess the distribution of potential net Non-Performance Charges and Performance Payments.
• determine the estimated annual total net Non-Performance Charges of a resource… probabilistic model that is also used in the reliability risk analysis and accreditation of resources, or ELCC model.
• factors include:
• the performance of the resource simulated under a broad range of system conditions and weather scenarios.
• the number and timing of modeled Performance Assessment Intervals… simulated in the model when the available supply falls below the load and reserve requirement in an hour, representing a reserve shortage and trigger for a Performance Assessment Interval.
• the Balancing Ratio
• the annual stop-loss for the resource.
• maximum exposure to Non- Performance Charges at a pre-defined confidence interval typically used in this value of risk analysis (i.e. 95th percentile).
• estimated cost of managing the risks of Non-Performance Charges, equal to a resource’s after tax Weighted Average Cost of Capital (“ATWACC”),
• determined consistent with the calculated value used in the capital recovery factor (“CRF”) formula in the avoidable project investment recovery (“APIR”) component
• Capacity Market Sellers may substitute their own estimate of a unit-specific risk cost and provide supporting documentation for such estimate.
• calculate the unit-specific CPQR value by multiplying the risk cost with the estimated exposure to risk of Non-Performance Charges that PJM calculates for that resource
• standardized unit-specific default CPQR value, calculated by the Office of Interconnection, would equal the default risk cost multiplied by the resource’s quantified risk at the 95th percentile.
• allowing Capacity Market Sellers of resources that will participate in the energy and ancillary service markets, regardless of receiving a capacity commitment, to reflect their respective cost of risk associated with capacity performance in their capacity market offers
• PJM is proposing a targeted amendment to allow resources that would continue to participate in the EAS markets even if they do not receive a capacity commitment to utilize a unit-specific Market Seller Offer Cap that is based on incremental costs that would be avoided only in the absence of a capacity obligation, such as CPQR, without an offsetting such costs with the resource’s expected net EAS revenues.43
• Tariff, Attachment DD, section 6.8(d-1) (“Notwithstanding the foregoing, in the case that the Capacity Market Seller has indicated in their submission of a unit-specific Market Seller Offer Cap that the resource will continue to operate and participate in the energy and ancillary services markets during the Delivery Year if not cleared in the capacity market, the Projected PJM Market Revenues shall be zero dollars.”).
• For these resources, letting the EAS revenues offset the applicable avoidable going-forward costs, including the CPQR component, does not result in mitigation of offers to a competitive offer level for such resources.
• Graf

• allowing segmented unit-specific offer caps,
• proposes to allow Capacity Market Sellers to submit unit-specific Market Seller Offer Caps that reflect incremental costs of having a capacity  obligation across different segments of a unit.
• the proposed rules specify that the first segment may include “incremental expenses directly required to operate a Generation Capacity Resource that a Generation Owner would not incur if such generating unit were to mothball or retire.”67
• all other offer segments can only reflect the incremental costs that would be avoided only in the absence of a capacity obligation for each of those segments
• Capacity Market Seller “must provide adequate justification for the use of a segmented offer cap with supporting documentation and calculations for the Market Seller Offer Cap of each segment”
• better aligning the Market Seller Offer Cap rules that may be applied to Planned Generation Capacity Resources with costs they may incur; allow Planned Generation Capacity Resources to seek unit-specific MSOC
• proposes to amend the default offer cap when a Planned Generation Capacity Resource is subject to being offer capped so that it will be equal to the default Net CONE values for the applicable technology in the Zone for which Sell Offer was submitted.53
• proposes to apply the same default gross CONE values specified in the MOPR provisions for Planned Generation Capacity Resources that are subject to the Market Seller Offer Cap
• calculation of the default Net CONE value would also be calculated consistent with the existing rules for previously uncleared resources that are subject to the MOPR.54
• For those resource types where no default Net CONE value exists, such as steam, oil, and diesel units, PJM proposes to set the default offer cap based on the Net CONE, which is used in setting the VRR Curve for
• proposes to allow Capacity Market Sellers of Planned Generation Capacity Resources to seek a unit-specific offer cap that is based on the Net CONE of such resource utilizing the same unit-specific Net CONE methodology that is already documented in the Tariff for new resources that are subject the MOPR.55
• providing more flexibility for PJM in approving a unit-specific Market Seller Offer Cap
• Under current rules
• the Market Monitor is allowed to “reach agreement with the Capacity Market Seller on the appropriate level of the Market Seller Offer Cap”60
• PJM’s review and determination is limited to “accept or reject the requested unit-specific Market Seller Offer Cap.”61
• proposes a simple revision that would also allow PJM to “calculate an alternative unit-specific Market Seller Offer Cap based on the submitted documentation.”6
• allow PJM to accept certain components of a unit-specific Market Seller Offer Cap that are consistent with the Tariff, rather than rejecting the entire requested unit-specific Market Seller Offer Cap outright.
• does not change the respective roles of PJM and the Market Monitor with regard to this process as it currently exists today
• PJM, with consideration of the Market Monitor’s input and determination, has ultimate approval authority of all Market Seller Offer Caps and the Market Monitor has the ability to escalate any disagreements on a PJM-approved Market Seller Offer Cap to the Commission for potential resolution
• any of the components that PJM does accept must consistent with the provisions detailed in the Tariff.

• CP enhancements
• aligning the eligibility of Performance Payments during Performance Assessment Intervals to committed Capacity Resources [severable]
• proposes to amend the eligibility of Performance Payments so that only committed Generation Capacity Resources that outperform their expected performance during a Performance Assessment Interval, up to their committed level of installed capacity, are eligible to receive Performance Payments
• proposes to cap the actual performance for Demand Resources, Price Responsive Demand, and Energy Efficiency Resources to the installed capacity commitment for such resources.95
• effectively preclude Demand Resources, Price Responsive Demand, and Energy Efficiency Resources from being eligible to receive Performance Payments, regardless of whether such resources have a capacity commitment.
• Reasoning

• Exclusion of DR, PRD and EE appropriate
• Demand Resources and Price Responsive Demand with the capability to provide reductions beyond their Firm Service Level should be incentivized to offer those additional amounts as committed capacity.101
• for Demand Resources and Price Responsive Demand, the expected performance or the level against which performance is assessed for the purposes of Performance Assessment Intervals, is set at the installed capacity level (rather than unforced capacity times Balancing Ratio as it is for Generation Capacity Resources)…expected resource adequacy value of such reduction to the Firm Service Level is assessed in the accreditation and risk analysis, where the load available to curtail is modeled as scaling proportionally with the level of system load.
• Further, as witnessed during Winter Storm Elliott, there may be little relationship to the actual load reductions from Demand Resources and Price Responsive Demand during a Performance Assessment Interval
• industrial and commercial loads were already reduced or offline on the Friday evening before the Christmas weekend and on Christmas Eve. This resulted in Demand Resources appearing to have outperformed their committed capacity during the Winter Storm Elliott event even though the vast majority of load had already been reduced beyond the committed capacity level regardless of whether a Performance Assessment Interval was declared
• Conforming modifications to Balancing Ratio
• Balancing Ratio numerator will be equal to the total committed Generation Capacity Resource’s actual performance, capped at the committed installed capacity equivalent for each resource.106
• Balancing Ratio numerator will not include any net energy imports or Demand Resource, Price Responsive Demand, or Energy Efficiency Resources given the proposed revisions discussed above.107

• clarifying when committed Capacity Resources are excused from Non-Performance Charges
• Despite the strictly circumscribed excusals set forth in Tariff, Attachment DD, section 10A(d), some Capacity Market Sellers still alleged that they met the requirements for an excusal because, despite being offline or unavailable during Winter Storm Elliott, they were “not scheduled to operate by the Office of the Interconnection.”69
• proposing to continue to strictly circumscribe excusals for planned and maintenance outage MW approved by PJM.
• online units will now be excused if they are dispatched by PJM to operate below their expected performance for reasons other than operating parameter limitations submitted in the resource’s operating parameters.
• PJM is removing the existing language where a resource would be considered in the calculation of performance shortfall where “the seller’s submission of a market based offer [is] higher than its cost-based.”
• proposes to make clear that if a unit is offline during a Performance Assessment Interval, it will be included in the performance shortfall calculation unless PJM dispatch affirmatively denies that unit’s request to come online.

• excluding any excused resources from the dominator of the Balancing Ratio
• establishing the ability for Market Participants to transfer performance obligations of Capacity Resources before a Performance Assessment Interval
• allow exchange of the Performance Assessment Interval obligations associated with committed unforced Capacity on a more granular (i.e., interval) basis than provided for under the current rules.
• allow Market Participants to adjust the expected performance of a Capacity Resource by entering into a bilateral capacity obligation transaction for the purchase and sale of a specified megawatt quantity of committed capacity that is subject to the performance obligations and provisions of Tariff, Attachment DD, section 10A.82
• seller’s PAI obligation on a resource is transferred to and received by the buyer’s resource.83
• must be reported and approved by both parties prior to the start of the effective time period of the transfer.84
• seller must guarantee and indemnify the Office of the Interconnection, PJMSettlement, and PJM Members for any failure by the buyer to pay any Non-Performance Charges owed to PJMSettlement associated with the transferred capacity.87
• receiving resource reported in the PAI Obligation Transfer must provide the same locational value of capacity as the transferring resource (taking into consideration the remaining import capability into Locational Deliverability Areas), and both resources must be included in the area of the Performance Assessment Interval;
• Resulting quantity of capacity that is subject to performance obligations on the receiving resource reported in the PAI Obligation Transfer cannot exceed the installed capacity or capacity interconnection rights of such resource.88
• payments and related charges associated with a PAI Obligation Transfer will be arranged between the parties to the transaction.
• removing the physical option for FRR Entities that underperform during a Performance Assessment Interval

• Forward looking Energy and Ancillary Service (“EAS”) offset for purposes of calculating the Market Seller Offer Cap and Minimum Offer Price Rule (“MOPR”)
• proposes the same approach for determining the net EAS for the Market Seller Offer Cap and the MOPR (with minor updates to certain values) as the Commission has twice accepted for determine the net EAS used in the VRR Curve.118
• proposes that the Market Monitor provide a preliminary Projected PJM Market Revenue by 150 days before each RPM Auction and a final Projected PJM Market Revenue value by 120 days before each RPM Auction.
• FRR Capacity Resources should have same financial incentives to perform during PAI as RPM procured resources
• proposes to phase out the physical option for FRR Entities by the 2025/2026 Delivery Year.
• proposes to provide FRR Entities the option of electing whether they are subject to the financial or physical penalty through the 2024/2025 Delivery Year.

• Includes a clarifying change that an EDC will verify whether a service proposed to be provided to PJM by a Component DER is already provided  (rather than receiving an explicit credit) through a retail program.  Providing a service through a retail program would preclude the sale/provision of that service to PJM.
• Allows an EDC to preclude the participation of a Component DER in the PJM energy, capacity and/or ancillary service markets if that Component DER participates in a Net Metering or other retail program, resulting in double counting – e.g. EDC can preclude participation of a Component DER in PJM regulation/reserve market if those services are provided (notably not credited per bullet above) through a retail program on the basis of double counting.
• Continues to preclude participation of Component DER in the PJM energy and/or capacity market at the same site where at least one resource is participating in a net energy metering program, unless the Component DER resource is separately metered with a distinct EDC account number.
• Generally maintains nodal aggregation requirement (with some evidence of prohibitive price deviation at zone/substation level), while giving the Commission the option to allow limited multi-nodal aggregations in the following circumstances:
• The multi-nodal DER Aggregation Resource may be comprised of one or more Component DER with capability smaller than 0.1 MW;
• Component DER at a single primary node with capability greater than 0.1 MW will be excluded from participation in the multi-nodal DER Aggregation Resource unless the total capability of all other Component DER in an aggregation is below the 0.1 MW participation threshold, as further described in the PJM Manuals;
• The multi-nodal aggregation must self-schedule into PJM’s energy market and must not be dispatchable; and
• The total capability of all multi-nodal aggregations across PJM’s footprint does not exceed 167 MW.
• Revises the utility review process into a 15 day preliminary review, and 45 day reliability review:
• Preliminary Review
• determine whether the Component DER meets the criteria for participation in PJM’s markets, as outlined in PJM’s Tariff
• provide primary electrical node
• EDC recommendation on PJM approval/denial
• Reliability review
• the Electric Distribution Company may perform any reliability assessments necessary to determine that the participation of the DER Aggregation Resource in the PJM energy, capacity, and/or ancillary service markets do not pose a threat to the reliable and safe operation of the distribution system, the public, or distribution utility personnel
• EDC recommendation on PJM approval/denial
• Clarifies that PJM will not interfere with EDC decision to override the dispatch of a DER Aggregation or Component DER.
• Clarifies that EDC override will not excuse any financial obligations of a DER Aggregator resulting from failure to perform on obligations under the PJM Governing Agreements (e.g. CP penalties).

• PJM does not admit to any violation of its Tariff or other wrongdoing as part of the settlement; and the settlement releases PJM of all claims arising out of WSE
• Includes allegations that PJM declared and maintained Emergency Actions when there was no ongoing emergency, nor any imminent threat of an emergency, in the PJM region
• 31.7% reduction in all parties Non-Performance Charges
• Percent reduction applied to each party’s Non-Performance Charges (interest on 9-month settlement also reduced)
• Bonus credits adjusted to reflect reduced NPC amount
• PJM to provide refunds/collect NPC/Bonus credits based on amounts previously collected/distributed relative to updated calculations
• Conditioned on payment in full of reduced NPC amount; otherwise (e.g. default) full amount is owed
• Additional adjustments to NPCs to resolve specific complaints
• EL23-56 (Talen) – credited $7.5M
• EL23-54 EL23-57 (Lee County) – credited $4.4M; PJM authorized to extend unpaid Non-Performance Charges (to avoid depleting collateral in support of export transactions); PJM/Lee County to extend payment obligations until settlement effective date; collateral applied to Non-Performance Charges if settlement effective date not prior to 6/1/24
• PJM to complete calculations and rebilling discussed above by next month invoice that is at least 60 days from settlement effective date
• If settlement rejected by the Commission, within 35 days (and the next two monthly invoices) PJM to invoice NPCs and interest deferred while settlement pending, plus interest of 6.31%
• Reserves two questions for Commission determination
• EL23-63 (Energy Harbor) – Settlement requests Commission make determination on this complaint on its merits based on record as of date of settlement filing
• PJM to apply settlement reduction to EH NPCs
• NPCs at issue (after reduction) $7.5M; to be held back pending Commission decision
• EL23-74 (EKPC) – settlement preserves right of EKPC to pursue claim requesting modification of the Non-Performance Charge rate and stop loss beginning with 23/24DY, per this complaint
• Settlement effective upon approval without condition/modification by the Commission
• If approved with condition/modification, settlement deemed withdrawn unless parties to settlement agree to Commission modifications/conditions, or agree to modify settlement to address Commission concerns within 10 business days
• PJM to adjust collateral held against NPCs for entities current on NPC charges at time settlement is filed; return collateral in excess of 1/3 the amount due if settlement does not become effective
• Request Mobile Sierra standard; i.e. public interest
• Request approval under Trailblazer (2) precedent:

• Based on fact that PJM and “overwhelming number of Market Participants” including NPC payors, zero NPC, and net performance payment recipients support the settlement or do not oppose it; thus any objecting party’s interests are represented by similarly situated participants in support of or not opposing settlement

• Settlement is mainly predicated on avoided litigation cost, time, uncertainty
• Supporting affidavits:
• Borgatti (Earthrise)
• Bryson (PJM)
• Berg (Constellation)
• Rohrbach (SMECO)

• Definition of Unlimited Capacity ICAP and seasonal impacts – i.e. ratings set assuming summer conditions, winter capability higher due to ambient derates; will this be accounted for?
• Will capacity operational test be applied to variable resources?
• Mechanism used to enforce dual fuel class definition
• Explain how PJM will model hourly output (for unit specific performance adjustment) for resources that:
• Enter commercial operation after June 1, 2012;
• Made a major change to plant design affecting their ELCC Class (for instance adding dual-fuel capability) after June 1, 2012; or
• Made other resource improvements that affect performance (e.g., fuel contract changes, weatherization, etc.) after June 1, 2012.
• Explain how differences between the resource mix and load assumed for the Portfolio EUE calculation, and the actual cleared resource mix and forecasted load affect: (1) resources’ ELCC Class Ratings, and (2) PJM’s compliance with the LOLE criterion of 0.1 days per year.
• Considering the fact that a Forecast Pool Requirement value less than one corresponds to a Reliability Requirement less than the annual forecasted peak load,  please explain to what extent a Forecast Pool Requirement value less than one may result in PJM procuring less capacity than PJM’s forecasted peak load.
• Regarding stop loss, considering the fact that under PJM’s proposal the BRA clearing price would not be known until after the auction completes…explain how PJM will evaluate sellers’ requests for a Capacity Performance Quantifiable Risk (CPQR) component in their unit-specific Market Seller Offer Caps
• Regarding notice of intent for planned resources:
• Please clarify how PJM would apply the binding notice of intent to a Capacity Market Seller that only intends to offer a portion of its resourceinto the corresponding capacity auction.
• Please clarify to what extent a Capacity Market Seller would be required to specify the quantity of capacityit intends to offer into the corresponding capacity auction, and whether this quantity would have to be specified in terms of installed capacity, Effective Nameplate Capacity, Accredited UCAP, or some other measure.
• Please clarify whether a Capacity Market Seller would have its preliminary ELCC Class Rating and resource-specific performance adjustment prior to submitting a binding notice of intent to offer.  If so, please describe the information provided to the Capacity Market Seller.
• Please clarify how the binding notice of intent would apply to a Capacity Market Seller that learns its resource will not be available due to factors beyond its controlduring the corresponding Delivery Year after it submits a binding notice of intent.

• Clarifications on review of CPQR under third party, default CPQR; CPQR generally
• Please clarify whether, per the proposed Tariff language, PJM and/or the Market Monitor will review a CPQR value that has undergone independent third-party review.  If so, provide additional details as to what type of review and how submissions will be evaluated.
• Please clarify whether PJM would be able to reject a CPQR value reviewed by an independent third-party entity, should PJM find it is not reasonably supported or consistent with the Tariff.
• Please clarify whether the proposed Tariff language provides an opportunity for PJM or the Market Monitor to review a CPQR value calculated under the standard CPQR formula.  If so, provide additional details as to what type of review and how submissions will be evaluated.
• PJM’s proposed Tariff states that, for the standard CPQR formula, a seller “may substitute their own estimate of Risk Cost with supporting documentation.”   Please provide additional details as to how PJM would evaluate such an estimate.
• The proposed Tariff modifies the definition of CPQR from costs of “mitigating the risks” of Non-Performance Charges to “mitigating, retaining, or otherwise managing the risks” of Non-Performance Charges.   PJM does not discuss this proposed revision in its transmittal letter.  Please provide support for this revision.
• PJM states that “[w]hile CPQR is the most direct example of a cost that can be avoided by not taking on a capacity commitment, there are others that could also apply.”   Please clarify how PJM will determine whether a cost is undertaken specifically for a capacity commitment.  Please provide examples of other costs that can be avoided by not taking on a capacity commitment.
• Clarify definition of “committed level of installed capacity” for purposes of capping Bonus Payments
• Clarify whether PJM denial of self schedule request creates performance excuse, or whether it is conditioned on denial due to system constraints/operational reasons
• Timing of self schedule request
• Self schedule request required to be “remade”/denied during PAI if previously denied to be excused
• Additional information on elimination of penalty in cases where resources not dispatched due to market based offer being higher than cost based offer