The Federal Energy Regulatory Commission and New York regulators will hold a joint technical conference Nov. 5 to discuss the state’s capacity market and plans to revamp the utility business model to accommodate renewable energy and distributed resources.
FERC’s conference with the New York Public Service Commission will be held from 9:30 a.m. to 5 p.m. at the New York Institute of Technology in Manhattan.
Reforming the Energy Vision
One focus of the conference will be the PSC’s Reforming the Energy Vision (REV) initiative, which the commission announced in April.
The PSC noted that technological innovation and the increased competitiveness of renewable energy and distributed resources is occurring as the state confronts aging infrastructure, extreme weather events and challenges to system security.
FERC Chairman Cheryl LaFleur said the commission wants to learn about how the REV program intends to reform the state’s energy industry and regulatory practices to meet these challenges.
“The New York PSC and New York leadership have produced some interesting things around their REV … that would potentially require evolution in the role in some of the things that we’re looking for from the ISO,” she explained after announcing the technical conference at last week’s FERC meeting.
The PSC released a straw proposal in August that found “There is large potential for the integration of Distributed Energy Resources (DERs) into the New York electricity market, via a Distributed System Platform (DSP) framework.”
The report outlined potential reforms in the utility ratemaking process “to provide the correct incentives for utilities and markets to develop a cleaner and more efficient electric system.”
A two-track public proceeding is examining the regulatory reforms. The first track examines the role of distribution utilities in deploying distributed energy resources to promote load management and system efficiency, including peak load reductions. The second, parallel track will consider changes in tariff and market designs and incentives to align utility interests with the policy objectives.
Public comment on the proposal was due yesterday.
Capacity Zone Controversy
The Nov. 5 conference will also be something of a fence-mending effort for FERC, following its approval of a controversial capacity zone intended to address transmission congestion north of New York City.
Opponents claim the zone, which took effect May 1, will create a windfall for existing generation owners before the region’s constrained supply issues can be full addressed.
In July, New York Sens. Charles Schumer and Kirsten Gillibrand voted against the reconfirmation of LaFleur, a fellow Democrat, to FERC. Before the vote, Majority Leader Harry Reid (D-Nev.) said he had spoken to LaFleur about the criticism of the capacity zone and that she had agreed to “take a hard look at” it. (See New Yorkers Upset over NYISO Capacity Zone.)
LaFleur Thursday acknowledged the controversy over FERC’s approval of the zone. “Those orders are final but it seemed like it might be a good time to consider: Is the capacity market attracting the investment we need for reliability? Let’s have a refresher on where we are,” she said.
The Public Service Commission has ruled that out-of-state companies can build and own transmission lines in the state, clearing the way for PJM to move forward with a solicitation process to upgrade lines delivering power from New Jersey’s Artificial Island nuclear complex. (See related story, Two of 4 Artificial Island Finalists Offer Cost Caps.)
The PSC’s opinion clarifies ambiguities in state law. One of four companies seeking to upgrade the transmission lines, Northeast Transmission Development, asked the PSC to make a determination.
PJM’s effort to upgrade the lines is the first time the transmission operator used FERC’s Order 1000 solicitation process, but it advised the four project finalists to seek a PSC opinion to resolve the legal uncertainty.
The Court of Appeals has ruled that state regulators should not have allowed Duke Energy to recover $61 million from customers for costs of building the Edwardsport coal gasification plant. The court ruled that the Utility Regulatory Commission didn’t conduct a comprehensive analysis before awarding the fees to Duke.
Exelon Facing Mounting Demands for Approval of Pepco Takeover
A group wants half of Pepco’s profits to be linked to performance standards in exchange for approval of its planned merger with Exelon.
The newly formed Coalition for Utility Reform wants the Public Service Commission to require “half of the merged entity’s profit to be determined by its ability to meet standards related to cost minimization, reliability, customer satisfaction, carbon reduction and environmental stewardship, distributed energy resources, customer control, and innovation.”
“This broad coalition recognizes that the current utility system is broken,” said Montgomery County Councilmember Roger Berliner, who filed the petition. The coalition plans to become an official intervener in the case.
Another group called PowerUpMontCo is asking for “a multi-billion dollar investment of capital into the infrastructure to bring Pepco’s long-neglected and dilapidated distribution system up to top-quartile service performance levels.”
Pepco shareholders are meeting to vote on the merger today.
A retired attorney from Chevy Chase is challenging Pepco’s rules requiring customers who don’t want a smart meter to pay a charge.
Deborah A. Vollmer, who fears that smart meters cause health problems and a loss of privacy, has refused to pay the opt-out fees. Pepco charges customers who decline a smart meter a $75 up-front fee plus $14 month. About 1,060 customers have declined to get the meters installed, but Vollmer is the only one who refused to pay.
Jonathan Libber, president of Baltimore-based Maryland Smart Meter Awareness, likened the opt-out fees to “protection money” that businesses pay to the mob. The organization seeks to educate the public about the potential dangers of smart meters and wireless devices generally.
Gov. Chris Christie named a Republican attorney and longtime friend as president of the Board of Public Utilities last week.
Richard Mroz, former chief counsel for Gov. Christine Whitman’s administration, would replace Dianne Solomon as head of the five-member board. Christie and Mroz were classmates at the University of Delaware. Christie previously named him to the Delaware River & Bay Authority in 2012.
Christie also nominated seven-term state Assemblyman Upendra Chivukula to fill a vacancy on the BPU. Chivukula, a Democrat, would step down from the legislature if confirmed to the utilities board.
The state Senate is expected to act on the nominations this week.
Coal Ash Law Goes in Effect Without McCory’s Signature
A new law requiring more stringent management of coal-ash ponds at power plants went into effect last week without Gov. Pat McCrory’s signature.
Lawmakers approved the bill last month in response to public uproar after a dam at one of Duke Energy’s coal ponds failed earlier this year, spilling 39,000 tons of ash into the Dan River. State law calls for the governor to either sign the law or veto it within 30 days.
McCrory, a former Duke employee, did neither. The governor said he thinks the bill violates his power and the state constitution and that he will ask the state’s Supreme Court to review it.
The Public Utilities Commission approved Dayton Power and Light’s plans to sell its 31% share of the 650-MW East Bend coal-fired power plant to Duke Energy Kentucky. PUCO agreed that the transaction will allow both utilities to better serve their customers.
Duke Energy will be sole owner of East Bend, giving it a hedge against the 2015 retirement of its 163-MW plant at Ohio’s Miami Fort Station. The sale needs the approval of the Kentucky Public Service Commission, which is expected by the end of the year.
American Electric Power plans a $21 million transmission-system upgrade to provide more power to two large oil and gas pipeline companies that are expanding operations in the state’s shale-gas region. The Public Utilities Commission has approved the project, which will upgrade the 69-kV line in Jefferson and Harrison counties to 138-kV.
AEP says it is responding to requests for more power from M3 Midstream and Access Midstream Partners. Shale-gas drilling has increased demand for electrical power at a rate unseen in the past.
“Most industrial load you can plan 18 to 24 months in advance,” said Dan Recker, AEP’s managing director of transmission engineering. “This is much faster than that. They were needing [electric] service in weeks instead of several months, and that really presented some challenges from a process standpoint.”
The Public Utility Commission has approved PPL’s pilot time-of-use program that is aimed at inducing customers to shift their energy use to off-peak hours to help meet the state’s energy-efficiency mandates.
The PUC approved PPL’s plan, which allows customers to sign up with third-party suppliers to get electricity at rates that adjust between off-peak and on-peak hours. The plan goes into effect Dec. 10.
The time-of-use rates should help PPL to comply with Act 129, a 2008 law that requires the state’s largest electric distribution companies to develop conservation plans to reduce consumption and shift load from peak hours.
The Public Utility Commission approved a settlement allowing Pike County Light & Power to increase revenue by 12.8% or $1.25 million, less than the $1.7 million the company originally sought.
The boost will increase rates for a typical residential customer by 16.2%, or from $93.06 a month to $108.10. The company has about 4,600 customers in Pike County in Northeastern Pennsylvania.
Utility’s Plan for Surcharge Irks Home Solar Customers
Appalachian Power’s plans to assess a fee on residential customers who have solar power systems has irked renewable power advocates.
The utility’s “standby charges” would cost customers with solar or wind systems connected to the grid about $3.77 per kilowatt per month. The fee would apply only to customers with systems rated between 10 kW and 20 kW, fairly large by residential standards.
State law allows for the charges if a utility can justify them, but some argue that Appalachian hasn’t proven its case. Appalachian says that customers with larger solar power systems are benefitting from the grid but aren’t paying to maintain the system.
The Federal Energy Regulatory Commission yesterday called for changes in ISO-NE’s capacity market rules, but split over whether it should reject the results from the ISO’s February auction due to unchecked market power.
Republican Tony Clark and Democrat Norman Bay called for FERC to reject the auction results, but Chairman Cheryl LaFleur and Republican Philip Moeller said the commission should seek only prospective changes in the auction rules. Because of the 2-2 deadlock, the 2017-18 auction results “became effective by operation of law” (ER14-1409).
In a separate docket (EL14-99), the commissioners unanimously ordered the ISO to defend its current auction rules or submit Tariff revisions creating a process for reviewing importers’ capacity offers and mitigating any market power. The commission set a 30-day deadline for the ISO’s response.
$3 Billion
The ISO’s eighth Forward Capacity Auction (FCA) resulted in a sharp price increase after nearly 3,000 MW of capacity submitted retirement requests. Fearing they would have less capacity offered than required, ISO-NE officials applied administrative price rules to the auction.
New resources in the Maine, Connecticut and Rest-of-Pool Capacity Zones will be paid $15/kW-month while existing resources in those zones will receive an administrative price of $7.025/kW-month. Both new and existing resources in the NEMA/Boston Capacity Zone will be paid $15/kW-month.
The ISO said total capacity costs for 2017/18 would be $3.05 billion, almost double the previous high ($1.77 billion in 2009).
Unlike other RTOs, ISO-NE’s capacity auction results are subject to commission review under the just and reasonable standard — the result of a 2006 settlement to address stakeholder concerns over the market design.
Clark and Bay issued a joint statement saying the auction results should be rejected and the matter set for a fast-track hearing and settlement procedures.
“Here, there is evidence suggesting the exercise of market power, and it is uncontroverted that the market power, if it existed, was not mitigated,” Clark and Bay said. “Moreover, it is possible that ISO-NE may have violated its Tariff in the way it conducted the auction. On this record, we do not believe that ISO-NE has carried its burden of establishing that the auction results are just and reasonable.”
LaFleur and Moeller said they would have approved the auction results because the ISO followed the rules previously judged just and reasonable.
“My objecting colleagues raise a valid point, that is, can an auction process that has previously been found to be just and reasonable produce results that are not just and reasonable? While such circumstances are not common, the answer is most certainly yes,” Moeller said in a statement. “However, in this case, while the prices resulting from FCA 8 were much higher than in prior auctions, the existence of very tight supply and demand fundamentals are primarily responsible for the FCA 8 results.”
After-the-Fact Ratemaking
In her statement, LaFleur said Clark and Bay’s position — that the commission not only determine whether the auction rules were followed but also assess whether the resulting rates were just and reasonable — would violate commission precedent and subject auction participants to “regulatory uncertainty or after-the-fact ratemaking.”
“I believe that respecting the established expectations of market participants as to the operation of the auction will be critical to the future ability of the FCM [Forward Capacity Market] to attract resources needed for reliability,” LaFleur said. “If market outcomes are accepted during times of excess capacity when the auction clears at the price floor, but the commission-approved auction rules are subject to retroactive revision when capacity is tight and market capacity prices are high, the long-term viability of the market is undermined.”
Even if the commission had authority to retroactively change the auction rules, LaFleur said, “The alternative approach begs the question of how to set the auction rates. Upon rejecting the existing, commission-approved auction rules, the alternative approach offers no guidance for establishing a just and reasonable replacement rate. This would be true whether the new rate were to be established by ISO-NE, the commission or a judge, because the only way to obtain a different rate is to change the underlying auction rules.”
Clark and Bay said LaFleur’s position “renders illusory the commission’s prior assurance [in approving the 2006 settlement] it would undertake a ‘thorough review of the final auction clearing prices.’”
“This alternative theory, to which we cannot subscribe, requires the commission to ignore the clear terms of the FCM settlement which the commission itself approved, and also requires the commission to accept as a fait accompli whatever price outputs are generated from the auction,” they wrote. “Under such a theory, not even allegations of unmitigated exercises of market power, nor referrals by a market monitor, could be taken into consideration by this commission, no matter the harm imposed on consumers.”
Unlike the first seven auctions, New England faced a capacity shortage entering FCA 8 after 3,135 MW of capacity, including the 1,535-MW Brayton Point generator, sought to retire before delivery year 2017-18. The retirement announcements came after the qualification deadline for new resources seeking to participate in the auction.
Instead of an expected surplus of more than 2,000 MW, the ISO went into the auction more than 1,000 MW short of its net Installed Capacity Requirement.
The ISO acknowledged that in “situations with limited excess supply, participants with a large amount of that supply are likely to recognize that they can be pivotal and set the auction price. Indeed, participants [in FCA 8] may have already been aware of the situation due to the publicly available information provided prior to the auction.”
Order to Show Cause
The commission’s Order to Show Cause is focused on rules specifying the Independent Market Monitor’s authority for reviewing offers from capacity imports.
The ISO’s Tariff requires its IMM to review import offers and reject any that the Monitor determines “may be an attempt to manipulate” the auction.
The commission said the Tariff limits the review to the qualification process, “and it only involves ensuring that the behavior of import resources was consistent with their actions in previous FCAs, rather than evaluating the bids of import resources for consistency with their net risk-adjusted going-forward costs, as is done for the offers of other resources.”
“Given the changing balance of supply and demand in New England,” the commission said, that provision “may be insufficient to ensure just and reasonable rates.”
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:30)
Members will be asked to endorse the following manual changes:
Manual 11: Energy & Ancillary Services Market Operations and Manual 15: Cost Development Guidelines will be revised to correct a typographical error. The words “mileage ratio” will be replaced with “mileage” in Section 3.2.7 of Manual 11 and Section 2.8 of Manual 15, where the calculation of adjusted regulation performance cost is described. There is no change in PJM’s calculations, which have been correctly using mileage as it is defined by PJM.
Manual 14A: Generation and Transmission Interconnection Process will be revised with the addition of a new section 1.14 regarding interim deliverability studies.
Manual 14D: Generator Operational Requirements will be updated as part of an annual review and include changes reflecting North American Electric Reliability Corp. standard MOD-025-2.
Manual 18: PJM Capacity Market will be amended to include details of the processes regarding maintenance outages for Annual Demand Response.
3. FTR/ARR Senior Task Force (FTRSTF) Problem Statement, Issue Charge and Charter (9:30-9:40)
Members may be asked to vote on changes in the scope of the Financial Transmission Rights Senior Task Force. The task force was formed to evaluate the causes for FTR underfunding and determine whether the current FTR and auction revenue rights processes to improve FTR funding levels. The proposed changes include an examination of the role of virtual transactions on revenue adequacy and proposed solutions by the Market Monitor.
4. Credit subcommittee Items (9:40-10:00)
Members will be asked to approve the following changes recommended by the Credit Subcommittee. The changes were approved by the Market Implementation Committee Sept. 3:
Risk Documentation Requirements – Remove the requirement that officer certifications be notarized and allow electronic submissions. Eliminate the requirement for annual submissions of risk policy documentation; PJM will accept certification that no substantive changes have been made since the last submission.
Peak Market Activity (PMA) Exclusions – Spot market energy, transmission congestion and transmission loss charges resulting from virtual transactions will be excluded from the peak market activity (PMA) credit requirement. Virtual transactions have their own credit screening rules. Screened export transactions also will be excluded from the PMA. The PMA is used to set baseline credit requirements for members based on historical activity.
Virtual and Export Transactions Credit Requirement Timeframe – Reduce the credit requirement timeframe for export transactions to two days from four days. The MIC approved a similar change in August for virtual transactions. (See PJM MIC OKs Settlement, Credit Changes.)
Demand Bid Volume Limits – PJM will establish a daily demand bid limit for each load-serving entity by transmission zone. Bids would be limited to the LSE’s calculated zonal peak load reference point for the day plus whichever value is more, 30% of the reference point or 10 MW. The 30% limit was based on analysis showing that the largest two-day-ahead zonal forecast shortfall from January 2013 through March 2014 was 28%.
PJM said the need for such limits was illustrated by the default of People’s Power & Gas in January. Due to an input error, the company entered a demand bid about 100 times the retailer’s load. Because demand bids are currently unlimited, bids exceeding actual load act as a decrement bid but lack the protections of the virtual transaction credit screen and minimum participation requirement.
5. Cap Review Senior Task Force (CRSTF) (10:00-10:30)
Members will vote on proposed changes to the $1,000 energy market offer cap.
Cost-based incremental energy offers would be limited to production costs as defined by Cost Development Guidelines plus 10% with no cap. Market-based offers would be limited to the greater of the cost-based offer or the offer cap for 30-minute notice demand response. Adders for frequently mitigated units (FMUs) and associated units (AUs) would not apply above $1,000/MWh. Market-based offers must be less than or equal to cost-based offers when cost-based offers are greater than the 30-minute DR offer cap.
The proposal won 63% support at the Cost Review Senior Task Force. If it does not win a two-thirds vote at the MRC, members may vote on an alternative proposal by Old Dominion Electric Cooperative and the Delaware Public Service Commission. It would allow offers above $1,000/MWh during Maximum Emergency Generation Alerts but would not allow the offers to set LMPs.
Members also will consider sunsetting the task force.
6. Capacity Senior Task Force (CSTF) (10:30-10:45)
Members will consider a proposed transition mechanism related to changes requiring more operational flexibility from DR providers. The change would allow curtailment service providers to designate previously cleared megawatts as “non-viable” — unable to meet the 30-minute-lead-time requirement. CSPs would be relieved of their obligations and have their capacity payments reduced.
The transition mechanism was developed to comply with the Federal Energy Regulatory Commission’s May 9 ruling on the DR changes (ER14-822).
Members also will consider sunsetting the Capacity Senior Task Force.
7. RPM: Capacity Import Limits – CTRs and ICTRs (10:45-11:00)
Members will vote on a problem statement and issue charge proposed by H-P Energy Resources to consider allowing qualifying transmission upgrades (QTUs) for capacity import limits. PJM instituted the limits on capacity imports in the May 2014 Base Residual Auction. (See Major Rule Changes Reduced Imports, DR.)
QTUs are currently allowed to increase the Capacity Emergency Transfer Limit (CETL) into locational deliverability areas (LDAs).
8. Transparency of TO Calculations (11:00-11:10)
Members will consider closing an issue relating to the transparency of the calculations transmission owners use for allocating energy, capacity and transmission costs. PJM has created a webpage listing the methodologies transmission owners use for calculating total hourly energy obligations (THEO), peak load contributions (PLC) and network service peak loads (NSPL).
The issue arose because some TOs have not filed tariffs disclosing the methodology they use. Some members complained that the lack of transparency made it difficult to ensure they were being properly charged. (See TOs Will Disclose Calculation Methodologies.)
Members Committee
2. CONSENT AGENDA (1:20-1:25)
Members will consider proposed revisions to the Operating Agreement clarifying the definition of supplemental transmission projects. Under the proposed revision, a supplemental project is one that is not a state public policy project and is not required for system reliability, operational performance or economic criteria.
The change removes a reference to supplemental projects as “Regional RTEP” (Regional Transmission Expansion Plan) projects. It also clarifies that any reliability upgrades required as a result of the supplemental project are considered part of that project and are the responsibility of the entity sponsoring it.
Members will be asked to endorse proposed Tariff revisions extending the deadlines for electric distribution companies (EDCs) to submit Power Meter and InSchedule data. The changes would allow load reconciliation data to be included in the calculation of balancing operation reserve deviation charges.
Members will be asked to endorse proposed Reliability Assurance Agreement revisions to allow EDCs to submit corrections to peak load contribution and network service peak load assignments until noon on the next business day. The changes, which will also be reflected in Manuals 18 and 27, are intended to aid Pennsylvania EDCs squeezed by new Pennsylvania Public Utility Commission deadlines. (See PJM MIC OKs Settlement, Credit Changes.)
PJM’s Board of Managers will seek approval of changes in capacity auction parameters despite load-serving entities’ requests that it delay action pending consideration of staff’s Capacity Performance proposal.
The board ordered staff to file changes resulting from the Triennial Review of the parameters with the Federal Energy Regulatory Commission by the Oct. 1 deadline set by PJM’s Tariff.
In a letter to stakeholders late Wednesday, CEO Terry Boston said the board had endorsed staff’s proposed changes in the shape and position of the capacity demand curve, which a PJM analysis indicated could add $1.5 billion to annual capacity costs.
The board ordered staff to revise the proposal to retain the backward-looking energy and ancillary services (E&AS) offset rather than a forward-looking methodology staff had proposed. The board also decided to use the Independent Market Monitor’s proposed labor cost estimates in the calculation of the cost of new entry (CONE) instead of those recommended by PJM’s consultant, The Brattle Group.
In letters to the board last month, stakeholders representing load interests said the board shouldn’t consider the parameter changes — which failed to win stakeholder consensus Generators: Capacity Performance Unrealistic, Unfair.)
“Given the importance of the [Reliability Pricing Model] parameters in maintaining investment in infrastructure to sustain reliability over the long term, the board believes updates to these parameters are required,” Boston wrote. “The report presented by the Brattle consulting firm indicates the current variable resource requirement (VRR) curve shape does not properly reflect the varying importance of procuring capacity as the system becomes shorter or longer and that a more responsive curve shape is required.
“It is also clear that the cost of new entry values are outdated and require updates.”
E&AS
The PJM Power Providers (P3 Group), American Electric Power, Dayton Power and Light and FirstEnergy Service all urged the board to file the curve changes without delay. But they expressed concerns over staff’s proposal to switch to a forward-looking E&AS offset.
AEP, Dayton and FE said staff’s proposal lacked enough details to warrant adoption. “We would support ongoing dialogue about the merits of a forward-looking E&AS for implementation at a future date although we are not persuaded that the time is ripe for making this change,” they said.
The P3 Group said it would consider a forward-looking offset. But it said staff’s proposal “incorrectly calculates the future revenues expected by a generator and fails to recognize the necessity for making parallel reforms to use a consistent methodology for developing market seller offer caps.”
Dynegy, which urged the board to delay action on the parameter changes, also cited the “mismatch” between the forward-looking offset and the backward-looking offer cap. Dynegy also said the proposed offset could be distorted by illiquid forward markets and potential gaming of futures contracts.
Labor Costs
The board’s selection of the Monitor’s labor cost estimate ($4,179/MW-year for 2018) represents a 10% increase over the Brattle estimate ($3,788/MW-year).
In his letter, Boston acknowledged that the Triennial Review “has been a complex and, at times, contentious set of issues with strong feelings on all sides.” He said the board’s action was intended to “ensure long-term reliability at a reasonable cost.”
“We appreciate stakeholder concerns regarding the pending Capacity Performance discussion, but it is important to recognize that the installed reserve margin (IRM) calculations and the Brattle analysis already assume a higher standard of resource performance than was observed last winter,” Boston said.
Generators said yesterday that PJM’s expectations for its Capacity Performance product are unrealistic and its proposed penalties unduly punitive.
The remarks came during a nearly four-hour meeting in which PJM staff answered stakeholders’ questions and Market Monitor Joe Bowring provided details on the sensitivity analyses the Monitor is conducting on the proposal.
Capacity Performance resources would be required to guarantee their availability during Hot and Cold Weather Alerts and Maximum Emergency Generation Alerts. The resources would need to demonstrate they can produce their committed installed capacity for 16 hours for each of three consecutive days.
Resources would be allowed to include in their offers a risk premium based on the 7% pool-wide EFORd.
“To allow a premium above that would undo the incentives,” Chief Economist Paul Sotkiewicz explained. “There would be no incentive for [generator owners] to do anything [to improve performance]. They would just take a flier and hope they don’t get called.”
Jason Cox of Dynegy said PJM is attempting to make generators shoulder all risks, despite widely acknowledged challenges to obtaining gas during the coldest days of the winter.
“It sounds like PJM is not asking for a 7% EFORd unit, they’re requiring a 0% EFORd unit,” said Cox, citing the requirement that units be able to refill oil tanks during a polar vortex. “That seems unrealistic to me.”
PJM officials said they are taking steps to improve gas-electric coordination. PJM’s Chantal Hendrzak said staff is considering allowing generators to make intra-day changes in cost-based schedules to protect generators from having to accept the risk of gas-price volatility. Stakeholders also are considering changes in the $1,000/MWh offer cap, which some generators said their costs exceeded in January.
Non-performance Penalties
Capacity Performance resources that fail to deliver during the alerts would face a penalty based on the hourly LMP and the size of their shortfall. PJM proposed capping the penalties at 2.5 times the resource’s capacity revenues for the year.
Generation owners would be permitted to avoid or reduce penalties by producing uncommitted megawatts from a non-CP unit. The netting would be based on the value of the power replaced — reflecting the different LMPs of the two units — not by the volume.
PJM wants 85% of the summer peak demand met by Capacity Performance, with the remainder coming from existing Annual Capacity (renamed “Base Capacity”), Extended Summer and Limited Demand Response offerings.
Jason Minalga of Invenergy said generators unwilling to assume the risk of non-performance as a Capacity Performance resource would be “crowded out” of the market because of the 15% cap on non-Capacity Performance resources.
“Correct,” replied Andy Ott, PJM executive vice president for markets. “That’s an incentive to become Capacity Performance.”
“This is completely asymmetric,” responded Minalga, citing what he called the “heavy administrative” role of the RTO and Market Monitor in approving capacity auction offers.
James Wilson, consultant to state consumer advocates, said PJM’s assumption that no Base Capacity would be available during the winter peak was “overly conservative” and would result in excessive costs to load.
“We know [that assumption is] not right,” Wilson said. He suggested the use of a probabilistic analysis to estimate how much would be available.
PJM’s Tom Falin said the assumption was based on the risk at the 95% percentile of load. ”That’s the only level at which risk occurs,” he said.
Monitor’s Analysis
Bowring said he hopes to provide stakeholders next week with results from sensitivity analyses on how PJM’s proposal might affect clearing prices and quantities.
The Monitor said the analysis will look at three ways generators might improve their performance to meet PJM’s requirements:
Securing firm gas service (estimated at $180/MW-day)
Having dual-fuel capability with five days’ storage capacity ($48 to $165/MW-day)
Five-day firm no-notice gas service ($10/MW-day, annualized)
To address withholding concerns, Bowring recommended capacity providers be required to submit “coupled” offers with different prices for Performance and Base products.
Schedule
Stakeholders will have until Sept. 17 to submit written comments on the proposal. The next meeting on the initiative is scheduled for Sept. 24.
Up-to-congestion trading plummeted by about two-thirds this week following a Federal Energy Regulatory Commission order that could result in sharply increased costs for traders.
On Aug. 29, the commission ordered a Section 206 proceeding to determine whether PJM is improperly treating UTCs differently than increment offers and decrement bids in the interpretation of a forfeiture rule and in the application of uplift charges.
UTC traders have pulled out of the market since Monday, when news of the proceeding was published in the Federal Register — triggering the clock on potential charges that UTC traders could face as a result of the FERC proceeding.
PJM saw both the volume of bids and MWh offered and cleared drop. Less than 500,000 MWh cleared yesterday, down from about 1.8 million the day before FERC’s order.
Attorney Ruta Skucas, who represents the Financial Marketers Coalition, had predicted the drop last week, saying that the market faced months of uncertainty while the case is pending.
The commission, which ordered — but did not schedule — a technical conference on the issue, said it expects to rule within five months after post-technical conference pleadings are submitted.
At a meeting of the Energy Market Uplift Senior Task Force yesterday, some stakeholders said the uncertainty could stretch out for years as occurred in MISO before it won FERC approval for its uplift rules, the Revenue Sufficiency Guarantee.
One trader told the task force he may have to resort to layoffs due to the uncertainty. “We’re not going to hemorrhage money waiting around” for a ruling, he said.
“Our traders have stopped trading as of yesterday,” said another.
But there was no consensus on how to avoid what one stakeholder called “the four years of paralysis” that MISO suffered.
Adam Keech, director of wholesale market operations, said PJM would like stakeholders to reach consensus on the UTC uplift issue so that the RTO can make a Section 205 filing before FERC weighs in. “We have this opportunity here to try to get ahead of it and try to influence FERC’s long-term interpretation on cost allocation,” he said. “I think that would be PJM’s preference.”
Some stakeholders, however, warned that in attempting a narrow Tariff filing, stakeholders might lose the opportunity for trade-offs that would be necessary for a broader, long-term solution.
Barry Trayers of Citigroup Energy said the task force should continue to follow the work plan it had before FERC’s order. “These are big questions and it’s very interwoven,” he said.
Noha Sidhom, general counsel for Inertia Power, said she was doubtful stakeholders would be able to reach a narrow agreement quickly, noting previous stakeholder efforts on the issue had been time-consuming and “very contentious.”
FERC’s order (EL14-37) came in response to a PJM filing in June defining UTCs as virtual trades and seeking to subject them to the RTO’s Financial Transmission Rights (FTR) forfeiture rule.
Assistant PJM General Counsel Steven Shparber said FERC’s “refund effective date” of Sept. 8 could apply to any rule changes regarding the FTR forfeiture rule. “Another plausible reading is that it also could apply to any uplift payments” later allocated to UTCs, he said.
Shparber said PJM does not plan to ask FERC for clarification on what would be covered under the refund. But he said “that could change” depending on the impact on market activity.
Lacking consensus, PJM will poll members beginning today on how they want to proceed. The options will range from seeking an expedited 205 filing to suspending EMUSTF’s work pending the outcome of FERC’s inquiry.
PJM has dropped a proposal to create a new real-time reserve market, bowing to stakeholder concerns over the cost and complexity of a solution that would be implemented only a few times a year.
Instead, PJM is finalizing a proposal that it says is a more flexible version of the short-term fix approved by stakeholders in May to limit uplift and capture reserve costs in energy prices. (See PJM Reserve Proposal Gets OK for Trial Run.)
The new proposal would not add new reserve products, require changes in settlement or cost-allocation procedures or increase the energy price cap ($2,700 effective June 2015).
Instead, it would add a second, lower step to the existing operating reserve demand curve for synchronized and primary reserves.
It would increase synchronized and primary reserve requirements under emergency conditions (Hot and Cold Weather alerts, Maximum Emergency Generation Alerts) when additional intraday resources are scheduled.
The volume added to reserves would be based on the Eco Max rating of the resources committed as opposed to the static 1,300-MW adder included in the short-term fix.
If PJM is short of the extended requirement, the lower penalty factor ($300) would set the clearing price; if it is short of the reliability requirement, the higher penalty factor ($850) would set the clearing price.
Interchange Limits
PJM also is considering limits on interchange during emergency conditions to prevent markets and operations from being whipsawed.
The limit would be used when operators have made firm resource commitments and anticipated interchange schedules are sufficient to meet projected load for the hour.
Spot imports and hourly non-firm point-to-point transactions submitted after the cap is implemented would be blocked once net interchange reaches the limit. Schedules with firm or network-designated transmission service would not be curtailed.
Notification
PJM said it will notify market participants of the potential for increased reserve requirements or the interchange cap the day before implementing them. Notification that the procedures have been implemented would be made one to two hours before the operating hour, PJM’s Lisa Morelli said.
PJM will notify the market of its actions via eData, eMKT, ExSchedule and the Emergency Procedures web portal.
The Energy and Reserve Pricing & Interchange Volatility Sub-Group will meet Sept. 16 and 29 to refine the proposals. PJM hopes to bring the issue to a stakeholder vote beginning in October.
Five years in the making, the Federal Energy Regulatory Commission has developed a comprehensive scorecard for comparing the performance of RTOs and ISOs, as well as utilities outside of organized markets.
FERC identified 30 common performance metrics tracking everything from system reliability to generator revenues and RTO administrative costs.
How well did PJM do?
The report, which covers 2006-2010, found that PJM lagged among its peers in wind forecasting accuracy, forced outage rates and congestion costs, but that the RTO excelled in generator interconnection processing, administrative costs and customer satisfaction.
Among the other metrics tracked are load forecasting accuracy, demand response participation, system lambda, net generation revenues and LMPs. The report also documented big disparities in the costs of feasibility, system impact and facility studies.
FERC Chairman Cheryl LaFleur said the report reflects “a desire to understand what drives success [in RTOs]. What’s that saying? If you can’t measure, you can’t manage.”
FERC staff is seeking public comment on the metrics and approval from the Office of Management and Budget to replicate the data collection for years after 2010.
The Federal Energy Regulatory Commission rejected an agreement between Duke Energy Carolinas and Duke Energy Progress to share capacity, saying the deal would be discriminatory.
The two companies, subsidiaries of Duke Energy following its acquisition of Progress Energy, said they created the capacity agreement to provide savings to their native load customers in North and South Carolina.
The agreement would allow the companies to “make temporarily excess capacity available to each other for time periods when” one party “is projected to have more capacity than is required” to meet reliability standards.
The companies said the capacity agreement would allow them to minimize purchases of capacity and “commitment of additional generation.”
The companies also said the sharing would be done “for no additional monetary compensation” because of the reciprocal nature of the agreement.
FERC was not persuaded. “Applicants have failed to demonstrate how sharing capacity with an affiliate at a zero-price term to the exclusion of other parties is just and reasonable and not unduly discriminatory or preferential under [Federal Power Act] section 205,” the commission ruled (ER14-2356).
The ruling does not affect the companies’ agreement to share economic dispatch of their owned and purchased generating resources.
