Page 1549 – RTO Insider

June 16, 2015June 15, 2023

What is Changing in PJM’s Proposal?

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)

June 15, 2015June 15, 2023

Norman Bay’s Dissent: ‘Two Carrots and a Partial Stick’

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.

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.

June 15, 2015June 15, 2023

How PJM Capacity Performance Compares with ISO-NE’s Pay-for-Performance

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.

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)

June 15, 2015June 15, 2023

SPP Takes on Grid Management in Great Plains

By Ted Caddell

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.”

June 15, 2015June 15, 2023

PJM Operating Committee Briefs

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.”)

SPS Removals in PPL

PPL Electric Utilities is removing three special protections schemes (SPS).

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.

— Suzanne Herel

June 15, 2015

PJM Transmission Expansion Advisory Committee Briefs

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.)

The recommendation has drawn comments and complaints from several losing bidders and the public service commissions of Maryland and Delaware, which objected to the cost allocation. The Delaware Public Advocate and Old Dominion Electric Cooperative also raised objections over the allocation.

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.)

The feedback was received from three entities that were unsuccessful in vying for the project: Ameren, ITC and LS Power’s Northeast Transmission Development.

“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.

— Suzanne Herel

June 15, 2015June 15, 2023

PJM Market Implementation Committee Briefs

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.

Proposals Address Tier 1 Synch Reserve Compensation

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.

— Suzanne Herel

June 15, 2015June 15, 2023

PJM Planning Committee Briefs

VALLEY FORGE, Pa. — PJM will propose a two-tiered fee schedule for proposed transmission projects, officials told the Planning Committee last week.

Instead of asking for $30,000 to study any project costing at least $20 million, it will request that amount only for projects of at least $100 million.

For projects between $20 million and $100 million, PJM will recommend collecting a fee of $5,000.

The $30,000 fee proposal was approved Feb. 26 by the Markets and Reliability and Members committees after the Federal Energy Regulatory Commission rejected as discriminatory a previous plan to apply the charge to all greenfield projects but not upgrades of less than $20 million. (See FERC Rejects Fee on Greenfield Transmission Projects.)

“Because we put this threshold in place, we were going to be collecting for a larger number of projects,” PJM’s Fran Barrett told the committee. “Staff said that we could find ourselves over-collecting.”

The Planning Committee will be asked to approve the proposal, which would be tested over a two-year period, at its next meeting on July 9.

The fee schedule would be applied based on the cost estimates presented by those proposing the projects.

“If it turns out that a lot of people are trying to get around that with [estimates of] $99,999,000 we’ll have to revisit it,” said Steve Herling, vice president of planning.

Task Force Would Create Standards for Order 1000 Projects

A problem statement and issue charge introduced on first read Thursday would create a task force to develop minimum design standards for competitively solicited greenfield projects under FERC Order 1000.

The idea arose from concern that the designated entities for such projects would not be required to follow the design standards of the zonal transmission owner.

“We don’t want this new product to fix one problem but introduce a weak point in the system,” PJM’s Suzanne Glatz said, reflecting stakeholder feedback.

The design standards would apply to transmission lines, substations, and system protection and control design and coordination. They would take into consideration geography and physical and local needs of the project.

The task force would be open to all PJM stakeholders and would report to the Planning Committee.

Still Searching for Ways to Incent Early Project Submissions

The committee endorsed a problem statement and issue charge to find ways to incent customers to submit transmission projects earlier in the queue window.

The issue will be assigned to the Planning Committee, which will have three to six months to identify better incentives to encourage earlier participation. (See PJM to Try Again to Speed Interconnection Filings.)

The imposition of non-refundable fees that escalate later in the queue window have had little effect on changing participants’ behavior, said Dave Egan, manager of interconnection projects.

Meanwhile, those who have done their due diligence in their submittals are being held up by late, deficient entrants, PJM says.

— Suzanne Herel

June 15, 2015June 15, 2023

Duke, ODEC Denied ‘Stranded’ Gas Compensation

By Michael Brooks

The Federal Energy Regulatory Commission last week rejected requests by two PJM generators seeking the recovery of “stranded” natural gas costs incurred during the polar vortex last year.

But the commission also ordered PJM to change its Tariff to allow generators to submit day-ahead offers that vary by hour and to update their offers in real time. PJM is the only RTO that doesn’t allow such variable offers.

Duke Energy (EL14-45) and Old Dominion Electric Cooperative (ER14-2242) both argued that they were owed compensation due to the events of January 2014, when a cold snap sent gas prices soaring. Duke purchased $12.5 million worth of natural gas for its Lee plant in Illinois, only to have it not called on in real time. Similarly, ODEC complained that PJM canceled multiple dispatches that left gas it had purchased for its plants unused.

ODEC also said its plants’ operating costs on Jan. 23, 2014, exceeded what it could recover in the day-ahead market due to the $1,000/MWh offer cap at the time. The co-op asked for an extension of the waiver FERC granted PJM on Jan. 24, which allowed capacity resources to receive make-whole payments if their costs exceeded the offer cap for a limited time.

Duke, which was able to resell some of its gas, sought $9.8 million, while ODEC said it was due nearly $15 million.

Different Arguments, Same Result

While PJM supported the companies receiving one-time waivers, FERC denied both requests, citing its rules against retroactive ratemaking. The commission said that in both cases, ratepayers had not given prior notice that they would be responsible for natural gas-related costs.

Additionally, FERC disagreed with Duke’s assertion that it was due indemnification under section 10.3 of the PJM Tariff, which the company claimed required PJM to hold it harmless for obligations to third parties as a result of directives from the RTO. Duke told FERC that PJM had effectively ordered it to buy gas on Jan. 27, as it was likely Lee would be called upon to maintain reliability.

Although PJM supported the waiver requests, it said it was not permitted to provide Duke relief under the Tariff. “Any extension of section 10.3 to cover the type of loss Duke incurred under the circumstances at issue would read the indemnification provision into a blanket insurance policy for losses of whatever sort, caused by accident, act of God or plain misfortune that a market seller may incur in responding to PJM dispatch,” PJM told FERC in response to Duke’s complaint. (See PJM Backs Duke’s $9.8M ‘Stranded Gas’ Claim.)

FERC agreed with PJM’s interpretation of the section. “The PJM indemnification provision should not be interpreted to guarantee reimbursement of a generator’s losses on gas purchases incurred in meeting its capacity resource obligations in PJM,” the commission said. “Fulfilling its energy market commitments are among the risks the generation capacity resource has assumed … when choosing to participate in the market.”

FERC also disputed Duke’s claim that PJM’s communication with Duke on Jan. 27 constituted a “directive” by the RTO. FERC said that PJM was merely advising that Lee was likely to be dispatched for reliability reasons.

And while PJM’s Independent Market Monitor objected to ODEC receiving compensation for its purchases of gas, it supported the co-op’s request to extend FERC’s waiver by a day in order to receive $2.7 million in make-whole payments. FERC said it saw no difference between the requests.

Offer Flexibility

FERC, however, found that PJM’s Tariff may be unjust and unreasonable because it does not allow generators to submit offers in the day-ahead market that vary hourly or to update their offers in the real-time market. ISO-NE gave its generators that flexibility in December, leaving PJM as the only RTO that does not allow such changes. (See related story, ISO-NE Prices Down Sharply in Q1; Generators Using Offer Flexibility Rule.)

The commission said it expects PJM to implement new rules allowing such changes by Nov. 1 and said refunds would be effective with the order’s publication in the Federal Register. PJM was ordered to report within 30 days on its planned response (EL14-45, EL15-73).

In April, the Markets and Reliability Committee authorized the creation of the Generator Offer Flexibility Senior Task Force to consider how to implement the changes under a problem statement proposed by Calpine, which is seeking $3.3 million in compensation for stranded gas-related costs (ER15-376). (See Bid for Generator Price Flexibility Draws Debate over 10% Adder.) The commission has not ruled on Calpine’s request.

Moeller Dissents

Commissioner Philip Moeller agreed with the majority that PJM’s Tariff was potentially unjust due to the lack of offer flexibility, but he said that he was “troubled” that it was unwilling to grant the companies any relief.

PJM’s “inflexibility contributed to the inability of generation units … to recover legitimate fuel costs,” Moeller said in his dissents to the orders. The companies “acted in good faith to preserve system reliability during a time of extraordinary system stress and deserve appropriate compensation.”

Moeller also said that the majority ignored the companies’ arguments and applied “an overly narrow reading of the prior notice rule and prohibition against retroactive ratemaking to find that ratepayers somehow lacked adequate notice that they would, in fact, be responsible for paying the cost of services provided to them to ensure resource availability during system emergencies.”

The complaints should have at least been set for hearing and settlement judge procedures, he said.

June 15, 2015June 15, 2023

Lake Champlain Cable into New England Progresses

By William Opalka

The second transmission line proposed to bring Canadian hydropower into the Northeast under Lake Champlain has advanced with the release of its draft environmental impact statement.

The New England Clean Power Link, proposed by Transmission Developers Inc.-New England (TDI-NE), is a high voltage, direct current line that would transport 1,000 MW of electricity 154 miles from Quebec to Ludlow, Vt. Ninety-eight miles of the cable would be buried under Lake Champlain, and most of its land-based route would be underground.

The U.S. Department of Energy released the draft on June 3 for the $1.2 billion for the project, which it says should be issued a Presidential Permit, required for the border crossing.

TDI also is planning another 1,200-MW line using a path underneath the lake and through existing rights-of-way to New York City. This project is furthest along the regulatory path, having received its final permits in April. (See Quebec-NYC Tx Line Clears Final Regulatory Hurdle.)

A third high-voltage transmission line proposed to transport Canadian hydropower into the Northeast, Eversource Energy’s Northern Pass in New Hampshire, is expecting its final EIS next month, as its review is taking longer than expected to complete. (See Eversource: Northern Pass Delayed Until ’19; Earnings Up.)

TDI-NE touts the Vermont project as a way to deliver renewable energy from Canada to the ISO-NE market. The company estimates that the regulatory process will take until the end of the year, with construction starting in 2016. The project is expected to be in service by 2019.

TDI-NE still needs permits from Vermont and has yet to announce customers for its electricity.

The release of the draft opens a 60-day comment period that is scheduled to close on Aug. 11.