Participants in evidentiary hearings will no longer have to provide paper copies of all exhibits introduced as evidence, under an order approved by the Federal Energy Regulatory Commission last week (RM15-5).
The commission said its administrative law judges recently adopted a practice requiring participants to file exhibits electronically. “Thus, it is no longer necessary or efficient to require all participants to provide the presiding judge and court reporter with paper copies of each exhibit introduced at the hearing,” the commission said. The order amends Rule 508 of the commission’s Rules of Practice and Procedure, which previously required participants provide one paper copy of each exhibit to the presiding officer and two paper copies to the court reporter.
The Federal Energy Regulatory Commission on Thursday accepted the results of ISO-NE’s ninth Forward Capacity Auction in February, turning aside the protest of a utility workers union (ER15-1137).
The Utility Workers Union of America Local 464 had challenged the results, charging that the Brayton Point Power Station illegally withheld capacity from the auction in order to drive up prices. (See Union: Void ISO-NE Capacity Auction Results.) The union tried unsuccessfully to make a similar complaint stick last year with the results of FCA 8.
“We are not persuaded by Utility Workers Union’s allegations that market manipulation affected FCA 9, as the record is devoid of any evidence to that effect,” FERC wrote.
The 1517-MW Massachusetts generator is slated to close in 2017. Energy Capital Partners, the plant’s former owner, did not offer it in the last two capacity auctions in New England, covering the 2017-2018 and 2018-2019 capacity commitment periods. Brayton Point was sold last year to Dynegy, which said it would close the plant on the previously announced schedule. (See Dynegy Becomes New England Player Overnight.)
The commission also said that Brayton Point was already prohibited from participating in FCA 9 having announced its intention to retire. The RTO’s Tariff prohibits re-entry into the capacity market “at market rates in years when market-based treatment is likely to produce more revenue, thus inappropriately toggling between cost-based and market-based compensation.”
The plant is located in the Southeast Massachusetts/Rhode Island zone, which failed to meet its minimum resource requirement, triggering administrative pricing. (See Prices up One-Third in ISO-NE Capacity Auction.)
MISO no longer faces a capacity shortfall next year, the RTO announced in releasing the results of its newest survey with the Organization of MISO States.
MISO said its newest results show a minimum 1.7-GW surplus for 2016 as a result of reduced load forecasts and an increase in resources committed to serving MISO load. The 2014 survey had projected a 2.3-GW shortfall next year.
The new survey predicts a regional surplus of 1.7 to 2.3 GW (representing reserve margins of 15.6 to 16.1%) for 2016, with sufficient zonal surpluses to offset zonal shortfalls through 2019. “Additional actions needed to ensure sufficient resources beyond 2019,” MISO said.
“The big change is in the increase of committed resources. There’s also a decrease in the reserve requirement as we continue to refine the calculations on exploiting the diversity of the footprint to minimize everybody’s obligation in reserves,” MISO Executive Vice President Clair Moeller said during a conference call with stakeholders Friday. “So going into 2016 we’re feeling very confident that we’re in good shape in terms of sufficient resources.”
The RTO said the survey projects an average annual load growth rate of 0.8% over the next five years, equal to the 2014 survey. However, because 2015 load forecasts were below previous projections, the growth was from a lower base level.
“At this point in time we see a shortage of physical machines to serve the load in 2020, premised on that 0.8% load forecast distributed across the footprint,” Moeller said. “So the question we’re trying to answer here is how tight will capacity supplies be in those out years so people can begin to make their decisions between purchase and build and demand-side management and whatever else they need to do to ensure they bring sufficient resources to the resource pool in these out years.”
Zonal Surpluses Can Offset Shortages in 2016
The forecasts also benefited from a 0.6-GW reduction in reserve requirements.
While the region will have sufficient capacity through 2019, according to the survey, Zone 6 (Indiana and Kentucky) and Zone 7 (Lower Michigan) will have shortfalls next year.
Generation owners, load-serving entities and regulators have been working to mitigate those problems, Moeller said. “We still have confidence they’ll figure out how to do that.”
By 2020, the survey forecasts regional capacity ranging from a surplus of 0.5 GW to a shortage of as much as 1.8 GW.
The RTO released its survey at its Annual Meeting in Milwaukee on Wednesday. Moeller said the survey would be explained in detail at the Supply Adequacy Working Group’s July 9 meeting.
The Federal Energy Regulatory Commission required several significant changes in PJM’s Capacity Performance proposal. PJM must make the changes in a compliance filing due in 30 days.
Below is a summary of the changes required, followed by the relevant paragraph numbers from the order.
Review of Sell Offers: The commission approved PJM’s proposed mechanism for reviewing and rejecting sell offers but required it to remove the phrase “to the satisfaction of the Office of the Interconnection” from Attachment DD, saying it was “too ambiguous and allows PJM too much discretion.” (¶92)
Good Faith Representation: The commission rejected PJM’s proposal that resources submitting Capacity Performance offers make a good faith representation that it has, or will make, necessary investments to ensure it has the capability to provide energy when called upon. Knowingly false representations would have been subject to penalties. The commission said it did not believe the representation “would provide any added value in incenting resource performance.” It also said the scope of the requirement was “inappropriately vague” and could create a barrier to entry for new resources. (¶94-5)
External Resources: FERC said PJM must add a requirement that an external generation capacity resource must demonstrate that it meets – or will meet by the start of the delivery year – the criteria for an exception to the Capacity Import Limit in order to offer as a Capacity Performance resource. (¶97)
Demand Resources, Energy Efficiency, Storage, Intermittent Resources: PJM must clarify that capacity storage resources, intermittent resources, energy efficiency resources and demand resources may submit stand-alone Capacity Performance sell offers in a megawatt quantity consistent with their average expected output during peak-hour periods. (¶100)
Environmentally Limited Resources: PJM must clarify that it will permit aggregated offers from environmentally limited resources. (¶101)
Aggregation Across Locational Deliverability Areas: FERC rejected PJM’s proposal to allow resources in different locational deliverability areas to submit aggregated offers, saying the RTO had not demonstrated why Capacity Emergency Transfer Limits should not be taken into account. “We are not persuaded that aggregation will be feasible across locational deliverability areas in all circumstances or would be able to provide the required resource adequacy during emergency conditions,” the commission said. In addition, it said the proposal was inconsistent with the Capacity Performance design, noting that several Capacity Performance rate parameters (non-performance charge rate, performance bonus payment rate, stop-loss limits, and default offer caps) are LDA-specific. (¶103)
Monthly Stop-Loss: The commission agreed with PJM’s request to withdraw its original proposal that the monthly stop-loss limit on penalties equal 0.5 times annual net CONE, which the RTO said would allow under-performance without consequence once a resource has reached the limit, equivalent to 15 performance assessment hours in a month. PJM acknowledged in its response to FERC’s March 31 deficiency letter that most performance assessment hours are likely to occur during a few peak months of the year. The commission said the monthly stop-loss limit would “severely dilute” PJM’s performance incentives. (¶165)
Non-Performance Charges: FERC required two clarifications to the language in proposed section 10A(d) of the Tariff “to avoid ambiguity or misinterpretation.” It said the proposed wording, “limitations specified by such seller in the resource operating parameters,” could be misinterpreted to mean only those operating parameter limitations that are less flexible than a resource’s pre-determined parameter-limited schedule. That, it said, could allow less flexible resources to avoid non-performance charges more often than more flexible resources. “We find that a clarification is warranted to make clear what parameter limitations are at issue in this provision.”
It also required PJM to make clear that if a capacity resource is not scheduled by PJM due to any operating parameter limitations submitted in the resource’s offer, any undelivered megawatts will be counted as a performance shortfall. The same penalty would apply to a resource that was not scheduled because its market-based offer was higher than its cost-based offer. (¶167-173)
Net Energy Imports: FERC required a clarification to avoid any ambiguity regarding how PJM will assess the performance of external resources, saying it agreed with the Market Monitor that the RTO’s proposal does not specify how PJM will assess performance for energy imports and when emergency action hours only occur within individual zones or sub-zones. “If an emergency action is limited to a zone or sub-zone region, transmission into the affected region is likely restricted, so including a system-wide measure of net energy imports would likely distort the balancing ratio,” the commission said. It also agreed with Panda Power Funds and the Coalition of Generators and Project Finance Resources (Essential Power, Lakewood Cogeneration, Moxie Freedom, CPV Power Development, NextEra Energy, Invenergy Thermal Development and Brookfield Energy Marketing) that, as proposed, the balancing ratio could exceed 1, causing capacity resources’ expected performance during a performance assessment hour to exceed their full cleared unforced capacity quantity.
It required PJM to submit revisions clarifying: the definition of net energy imports; how it will apply the performance assessment calculation to external resources with and without a capacity commitment when an emergency action is triggered PJM-wide; and that a capacity resource’s expected performance for any performance assessment hour shall not exceed 100% of its cleared UCAP quantity. (¶175-178)
Fixed Resource Requirement Entities: FERC said PJM’s penalties rate could unduly penalize Fixed Resource Requirement (FRR) entities because the physical penalty option lacks an hourly charge rate relative to the additional capacity per megawatt of non-performance. It required that PJM propose a penalty rate for the physical payment option in terms of additional capacity per megawatt-hour of non-performance. It also required the RTO to allow FRRs to choose between the physical non-performance assessment option and the financial non-performance assessment option at the start of the delivery year, rather than when the FRR submits its first capacity plan. “We find that this delay will allow a Fixed Resource Requirement entity to make its decision on the best information available.” FERC also said PJM may apply the Capacity Performance rules to FRR entities only after the conclusion of the FRR plans to which they are currently obligated. (¶208-212)
Exemption for Planned Generation Resources: FERC rejected PJM’s proposal to exempt planned generation capacity resources from the capacity market must-offer requirement until they become operational. “We are not persuaded by PJM’s concerns that continuing to apply the must-offer requirement to planned resources that have cleared at least one RPM auction would act as a barrier to entry. In addition, we are concerned that by clearing an RPM auction with a planned resource but not following through on its construction in a timely manner, a seller could effectively withhold capacity and deter a new entrant from taking its place,” the commission said. It noted that PJM’s current rules allow resources not expected to become operational as planned to seek an exception to the must-offer requirement. (¶ 353-356)
Credit Requirements: FERC agreed with PJM that the risk of non-performance is higher for resources that do not exist at the time a seller submits an offer but said its proposal did not acknowledge changes in the risk as a resource transitions through the stages of development. It required PJM to modify the proposed credit requirements for planned resources and financed resources, as recommended by Panda Power Funds, to allow the security requirement to be reduced as the project nears its in-service date. FERC also required PJM to revise its credit requirements to recognize LDA-specific net CONE values in determining a market seller’s auction credit rate. (¶382-383)
Operating Parameters: The commission rejected, in part, PJM’s proposed revisions to rules on operating parameters. FERC said PJM’s existing rules allow capacity resources to submit energy market offers with inflexible operating parameters that do not reflect their actual capabilities. As a result, generators could offer excessive minimum run times, resulting in unjust make-whole payments at ratepayers’ expense, the commission said. But it called PJM’s proposed changes “overly restrictive,” saying the RTO’s proposals for capping the minimum start-up and notification times for all resources and for capping the minimum down time of storage resources did not take into account unit-specific constraints.
It also found fault with PJM’s proposal that offers reflect only physical constraints, saying it barred resources from reflecting in their offers contractual limits, such as gas pipeline requirements that generators take uniform delivery throughout the day, which could result in longer minimum run times. The commission said including such constraints in a supply offer is reasonable and not an exercise of market power, as PJM had contended in proposing that resources that do so be denied make-whole payments. “We see no reason to treat costs associated with resource physical constraints differently than costs associated with other types of actual constraints,” the commission said.
It ordered PJM to revise the rules to allow make-whole payments based on “actual constraints.” However, the commission rejected arguments that a resource’s inability to perform due to such limitations should be excused when calculating capacity payments. “The revisions that we direct here ensure that resources are appropriately compensated for their operation in the energy market; they do not excuse a resource from failing to fulfill its capacity obligation,” the commission said. “Providing such an exemption from non-performance charges would blunt the incentives for providing energy and reserves during the hours when they are most needed. … Accordingly, it is reasonable for a resource that fails to perform because of parameter limitations to receive less net capacity revenue than a performing resource.” (¶437-440)
Maximum Emergency Offers: The commission said PJM had failed to make a case that its current rules regarding maximum emergency offers are unjust and unreasonable, rejecting its proposed changes. PJM said the rules allow a generation capacity resource to submit an uneconomic offer price, removing itself from the day-ahead energy market until PJM has declared a maximum emergency. FERC acknowledged that the rules may allow a capacity resource to avoid honoring its capacity commitment. “However, we conclude that proper application of non-performance charges, rather than revision of the maximum emergency offer designation, is the appropriate method of eliminating this concern,” the commission said. PJM’s proposal could unintentionally reduce the number of resources available during emergency conditions if the resource’s alternative action is to take a forced outage, FERC said. “There is, therefore, value in allowing a Capacity Performance resource to offer capacity on an emergency-only basis when it is subject to environmental limitations, fuel limitations, or temporary emergency conditions, or when it can provide its capacity on a temporary basis only.” (¶476-479)
The Federal Energy Regulatory Commission gave PJM virtually all it asked for in approving its Capacity Performance proposal. But Chairman Norman Bay’s dissent may provide ammunition for a potential challenge in federal court.
(Source: FERC)
Bay predicted the proposal would not accomplish its stated goals, calling it “two carrots and a partial stick.”
One “carrot,” Bay said, allows resources to offer up to about .85 of the net cost of new entry (CONE) — or more if a resource can justify higher unit specific costs. The second carrot entitles resources that overperform a share of penalties collected from units that fail to perform.
Bay said the “stick” may provide insufficient deterrence because it is based on an estimate of 30 “performance assessment hours” — hours in which PJM declares emergency actions — annually. The 30-hour estimate is based on the number of such hours during delivery year 2013/14.
Bay said this is “overly generous” because PJM declared only seven and five performance assessment hours in 2011/12 and 2012/13 respectively — an average of 14 hours over the three-year period, or six hours if the “outlier” of 2013/14 is excluded.
If PJM declared 14 performance assessment hours in a capacity zone, a resource that failed to perform during each of those hours would be subject to a total non-performance charge of 14/30 times .85 net CONE, or .40 of net CONE for the delivery year, Bay said. That means non-performers could profit as long as the auction clearing price is larger than 0.40 net CONE.
“A rational profit-maximizing resource could simply seek a capacity award in the auction, fail to perform during each performance assessment hour and likely pay a penalty less than the carrot it has received,” Bay said.
Bay said the changes also will incent generators to raise auction clearing prices up to .85 of net CONE, because only prices above that level are subject to unit specific reviews.
“The temptation to exercise market power in the auction will be considerable. This would be less of a problem if one could count on the salutary benefits of competition. But, as PJM and the Market Monitor recognize, this market is structurally non-competitive. And the mitigation rules that are usually the safety net in such markets have largely been removed. Thus, the CPP creates the very real risk of the unmitigated exercise of market power up to .85 of net CONE.”
The commission majority ordered PJM to review the 30-hour metric annually to evaluate whether it remained appropriate. It also said that a penalty rate based on net CONE rather than energy prices or capacity clearing prices “is more likely to prevent non-performing resources from receiving positive net capacity revenues over the long run.”
Bay said the commission should have required a cost-benefit analysis before approving the proposal. “Given the potential multi-billion dollar cost … and the burden consumers will be asked to bear, any analysis, no matter how rudimentary, would have been helpful before concluding this proposal is just and reasonable.”
The commission said it did not need the “mathematical specificity of a cost-benefit analysis” to decide the case. “Rather, the commission considers the proposal in light of the currently effective tariff and comments in support and opposition to reach its determination,” it said.
Bay contended Capacity Performance’s cost may outweigh any benefits, citing PJM’s estimate that it would cost $1.4 billion to $4 billion annually. While PJM experienced uplift payments totaling $667 million in January and February 2014, uplift dropped to $105 million for the same months in 2015.
“One way of viewing the CPP is that it fixes a several hundred million dollar uplift problem in the energy market with a multi-billion dollar redesign of the capacity market,” Bay said.
PJM’s Capacity Performance plan approved by the Federal Energy Regulatory Commission borrows elements from ISO-NE’s Pay-for-Performance program. Below is a summary of some key differences between the two plans followed by the relevant paragraph numbers from the order.
ISO-NE’s ninth Forward Capacity Auction in February saw prices increase by about one-third as 1,400 MW of new resources cleared to replace retiring coal plants. ISO-NE officials credited its new Pay-for-Performance incentive — used for the first time in FCA 9 — a sloped demand curve and a seven-year price lock-in for new resources for the results.
Annual Stop-Loss Limit: PJM’s annual non-performance charge stop-loss limit is equal to 1.5 times the annual net cost of new entry (CONE) rather than the auction clearing price as in ISO-NE. The commission acknowledged that PJM’s stop-loss limit will likely be higher than ISO-NE’s but said it was reasonable. “An important element of PJM’s overall proposal is to put at risk full capacity auction revenues if a resource completely fails to perform during performance assessment hours. Because the proposed annual stop-loss limit is equal to the maximum clearing price allowed by PJM’s Variable Resource Requirement curve, it meets this criterion,” FERC said. “In addition, basing the limit on net CONE ensures that market participants will know their maximum risk exposure in assuming a Capacity Performance commitment and be in a position to formulate their sell offers accordingly.” (¶164)
Trigger for Performance Assessment Hours: PJM will use the declaration of Emergency Actions as the trigger for performance assessment hours. In contrast, ISO-NE’s trigger is a shortage of system 30-minute reserves, system 10-minute reserves or zonal 30-minute reserves. “While PJM’s proposed trigger is more expansive, to include certain warnings and pre-Emergency Actions, we find that PJM’s approach would accurately correspond with conditions and events during which the system is experiencing, or may reasonably expect to experience, a shortage of capacity,” the commission said. “We find that this approach will appropriately trigger performance assessment hours when performance is most critical to the PJM system.” (¶186)
Transition Mechanism: FERC said PJM’s transition mechanisms strike an appropriate balance between procuring too much or too little capacity able to qualify as a Capacity Performance resource. Although the commission approved ISO-NE’s proposal to acquire only its performance product in its next auction, “PJM has demonstrated that a phased-in approach is also just and reasonable,” FERC said. (¶256)
Withholding: The commission rejected the Market Monitor’s suggestion that PJM adopt ISO-NE’s use of resources’ installed capacity values to define required performance. The Monitor said PJM’s reliance on unforced capacity could result in withholding by allowing a supplier with a large portfolio to reduce its available capacity from some of its resources to result in a higher clearing price for the entire portfolio. Such suppliers also could reduce unforced capacity available from some of its resources as a hedge against unexpected outages on other units. The commission said “the likelihood of such a strategy is mitigated by a resource deliberately forgoing considerable energy revenue in the hopes that the withholding strategy and any additional performance payments during Emergency Actions would outweigh the forgone energy revenue.” It said the Monitor should work with PJM to devise an alternative mitigation mechanism if it finds evidence of such strategies. (¶358)
Application of Non-Performance Charges: The commission approved PJM’s proposed application of non-performance charges, although it said it was “more lenient” than that applied by ISO-NE. It noted that the “more significant” of PJM’s proposed revisions regards generator maintenance outages as opposed to planned outages. “We agree with PJM that a generator on a planned outage should not be expected to return to service within a time interval of less than 72 hours. We also find reasonable PJM’s proposal requiring a generator on a planned outage to provide PJM with an estimate of the amount of time it will require to return to service. This requirement presents no significant burden to the resource but will assist PJM in operating its system during tight conditions,” FERC said. (¶496)
SPP has expanded its electric grid management from eight to 14 states, adding more than 5,000 MW of peak demand and 9,500 miles of transmission lines in the Great Plains.
The move, effective June 1, brings into SPP the Integrated System: the Western Area Power Administration’s Upper Great Plains Region (Western-UGP), based in Billings, Mont.; Basin Electric Power Cooperative in Bismarck, N.D. and the Heartland Consumers Power District in Madison, S.D.
Western-UGP becomes the first federal power agency to join an RTO under the Federal Energy Regulatory Commission’s Order 2000, which encouraged the voluntary formation of independent grid operators.
FERC approved SPP’s incorporation of the Integrated System in November (ER14-2850). While its grid is now under SPP’s control, the region won’t take part in SPP’s markets until October.
SPP COO Carl Monroe said Monday that the integration — which represents an increase of about 10 to 12% increase in peak load — has been seamless so far.
“The way we measure the success of the transition is if we hear no noise about it,” he said. He said it’s been quiet, and SPP is working on the next step of integrating the new organizations into the SPP tariff. He said Western-UGP, Basin Electric and Heartland Consumers are already participating in SPP’s transmission planning process.
Basin Electric has 2.8 million customers and 2,100 miles of transmission lines. Heartland serves 28 municipalities, including Sioux Falls, S.D. Western-UGP covers 378,000 square miles of prairie and farmland. The Integrated System evolved from a 1962 agreement between the Bureau of Reclamation, Basin Electric and 103 cooperative and municipal preference customers in the region. The SPP Board of Directors approved the system’s membership in June 2014.
It marks a significant increase in authority for SPP, which had shrunk after Entergy defected to MISO. The shifting of companies from one RTO to another spurred the need for settlement conferences overseen by FERC. Some issues are still in dispute, including MISO-directed transactions that flow across SPP territory.
The expansion will “enhance our ability to deliver value through transmission,” SPP CEO Nick Brown said. “The Integrated System’s footprint is well connected to SPP’s existing service territory and provides a logical expansion from a network configuration standpoint.”
SPP says the expansion will result in stakeholder net benefits of about $334 million. These include the increased ability to commit and dispatch generation into and out of Nebraska, and the availability of low-priced hydro generation out of Western-UGP.
Monroe thanked the Integrated System’s efforts in easing the transition. “Coordinating the flow of power requires hard work and collaborative planning,” he said. “We look forward to completing the Integrated System’s full membership in SPP this fall, which will provide increased options for buying and selling power.”
VALLEY FORGE, Pa. — PJM staff introduced a problem statement at last week’s Operating Committee meeting to address concerns that the RTO is purchasing too much fast-responding “RegD” resources, which is negatively affecting regulation and reliability.
The problem statement calls for a reevaluation of the marginal benefits factor used in the regulation market optimization solution, which appears to over-value the contribution of RegD resources as a substitute for traditional RegA.
“In order for the regulation market to arrange the optimal, least-cost combination of RegA and RegD to meet [area control error] control requirements, the marginal benefits factor function needs to be accurately defined,” according to the problem statement. (See PJM Market Monitor: Faulty Marginal Benefit Factor Harming Regulation.)
Generators’ Non-Compliance Continues
PJM staff continues to struggle with generators’ non-compliance with training and certification requirements.
While transmission owners generally are in compliance, 10 generators (12%) were non-compliant for certification, and two (3%) were non-compliant for training as of May, PJM’s Glen Boyle told the Operating Committee. Four demand response companies (17%) were non-compliant for training. In addition, four small generation companies (20%) were non-compliant for training.
While non-compliant companies are supposed to submit mitigation plans, many have not, and there are no financial penalties for failing to do so.
Stakeholders suggested PJM identify a compliance officer at each organization with whom to follow up. (See PJM Operating Committee Briefs,“Sought: Ways to Incent Training, Certification Compliance.”)
Susquehanna Loss of Outlet Scheme: The SPS would trip Susquehanna Unit 2 when two 500-kV outlets were open at the same time. The SPS is no longer needed with the May addition of the Susquehanna-Roseland 500-kV line.
Wescosville T3 SPS: The Wescosville 500/138-kV Transformer T3 would trip when the Alburtis end of the Susquehanna–Wescosville-Alburtis 500-kV line was open. The SPS is no longer needed with the May installation of the Breinigsville 500/138/69-kV substation.
Montour Runback SPS: During construction of the 230-kV line between Lackawanna and Bushkill and on one of the two Susquehanna-Harwood 230-kV lines, certain contingencies could overload the remaining second line. This SPS either reduced the output of Montour Units 1 and 2 or tripped the units to alleviate the overload. The SPS is no longer needed with the rebuilt line between Lackawanna and Bushkill and the Susquehanna-Harwood lines being back in service. It is blocked and will be removed in September.
VALLEY FORGE, Pa. — Maryland and Delaware officials are protesting PJM’s proposal to allocate most of the cost of the stability fix at Artificial Island to Delmarva Power & Light ratepayers.
PJM planners expect to present their recommended fix to the Board of Managers on July 27, after a meeting with the board’s Reliability Committee, which is made up of four of the board’s 10 members.
The project has been mired in controversy since planners last summer recommended Public Service Electric & Gas for the job, only to have the Board of Managers reopen the bidding following an outcry from finalists, environmentalists and New Jersey officials. On April 28, planners completed a second review, recommending selection of a proposal by LS Power. Including upgrades by PSE&G and Transource, the project is expected to total more than $200 million. (See PJM Staff Picks LS Power for Artificial Island Stability Fix; Dominion Loses Out.)
Steve Herling, vice president of planning, told the Transmission Expansion Advisory Committee that the allocation is based on the location of the solution, not the problem. In this case, while the stability fix affects nuclear generators located in New Jersey, the project would entail transmission terminating in Red Lion, Del.
In its letter to the board, the Delaware PSC estimates that the AI fix could boost Delmarva’s annual transmission revenue requirements by $30 million over the current $121 million, an increase of almost 25%. Ratepayers of ODEC and the Delaware Municipal Electric Corp. also would be affected.
The Maryland PSC echoed its neighboring state’s concern, saying, “We do not view such a cost allocation as reasonably comparable to the benefits received from the project, which we believe would flow equally to at least New Jersey and Pennsylvania residents. Thus, such an allocation of costs, we believe, is in violation of FERC’s Order 1000 cost allocation principles and directives.”
PJM Holds Firm on its Pratts Decision
PJM planners reaffirmed their recommendation to select Dominion Resources and FirstEnergy to resolve reliability problems near Pratts, Va., despite feedback from several stakeholders questioning their decision. (See Tx Developers Challenge PJM Choice on Pratts Project.)
“We’ve been pretty consistent in the way we’ve been evaluating all the proposals submitted in a proposal window,” said Paul McGlynn, PJM general manager of system planning, noting that the key factors in PJM’s decision were performance, cost and risk associated with siting, feasibility and cost commitment.
PJM will continue to accept comments regarding the decision until July 13. It plans to make its recommendation to the Board of Managers at its meeting July 27.
VALLEY FORGE, Pa. — A months-long debate over whether to create “historic” capacity rights for some load-serving entities took a twist last week when PJM staff returned with a different proposal angled to achieve the same result.
“This has very little similarity, if any, to the previous approach,” PJM’s Jeff Bastian told the Market Implementation Committee on Wednesday.
PJM has been wrestling with how to help the Illinois Municipal Electric Agency meet its internal resource capacity requirements when it needed to use resources located outside of the Commonwealth Edison locational deliverability area to serve its Naperville, Ill., load. (See PJM Debate over ‘Historic’ Capacity Rights Gets a Face: IMEA.)
After failing to gain traction with skeptical stakeholders, staff veered from the notion of “historic” capacity to recommend a proposal that would apply only to Fixed Resource Requirement (FRR) entities — LSEs permitted to avoid direct participation in the Reliability Pricing Model auctions by meeting their capacity requirements using internally owned resources.
Under a proposal approved by PJM, the Independent Market Monitor and IMEA, the internal capacity requirement would not have an effect unless there was price separation for the relevant LDA.
IMEA will put in its offer after PJM defines the auction parameters. If its LDA has price separation when PJM clears the auction, it will be required to meet the internal requirement for the next auction, avoiding the internal capacity rule for only one auction, Market Monitor Joe Bowring explained.
The changes put IMEA where it was before PJM changed the rules regarding the trigger for the internal capacity requirement.
“Within an LDA that is being modeled separately, for reasons other than [Capacity Emergency Transmission Objective or Capacity Emergency Transmission Limit] threshold test or non-zero locational price adder in past three auctions, the FRR entity would not be subject to an internal minimum requirement until the first year after the LDA actually in an auction — or they could resort back to RPM the following year,” Bastian said.
Stakeholders, however, asked for more information regarding the thought process behind the changes before they considered approval.
Committee members were presented with the first read of three competing proposals addressing the issue of how to compensate Tier 1 synchronized reserves.
Since October 2012, Tier 1 reserves have been compensated at the synch reserve market clearing price (SRMCP) when the non-synch reserve market clearing price (NSRMCP) is greater than $0. While Tier 1 reserves are paid the same as Tier 2, only the latter is subject to penalties for non-performance.
The problem statement the proposals seek to solve asks whether it’s appropriate for such reserves to be credited when they are not responding to a synch reserve event, and if so, how much? (See Monitor: Cut Pay for Tier 1 Synchronized Reserves.)
Tier 1 reserves are made up of on-line resources that are able to ramp up from their current output within 10 minutes in response to a synchronized reserve event.
The proposals come from PJM, the Independent Market Monitor and PJM’s Industrial Customer Coalition.
The PJM proposal would retain the status quo of paying Tier 1 reserves the SRMCP when the NSRMCP is greater than zero. The ICC recommends paying the non-synch reserve price in that scenario. The Monitor says Tier 1 resources should not be paid except during a synch reserve event.
PJM’s proposal alone would impose an obligation on Tier 1 resources to respond, with a refund owed for nonperformance.
Independent Market Monitor Joe Bowring said the payments to Tier 1 resources are an unnecessary “windfall” that have totaled up to $15 million in the first quarter of this year alone.
“There’s no reason to pay Tier 1 anything additional than what they’re being paid now,” Bowring said. “That’s fully compensatory for what they’re doing.”
Changes Would Allow Earlier Replacement Transactions
The committee will be asked to vote at its next meeting on manual changes that would allow replacement capacity transactions earlier than Nov. 30 prior to the start of the delivery year.
Such replacements would be permitted when the owner of the replaced resource could show the expected final physical position of the resource at the time of the request.
Existing generators could engage in such transactions if they are being deactivated, while new generators could replace themselves if their project is cancelled or delayed. Demand response or energy efficiency resources could be replaced due to the permanent departure of their loads.
Resources replaced would not be able to be recommitted for the delivery year.
