PJM Board Orders Filing on Capacity Parameter 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 last month — until it evaluates how they would interact with the new Capacity Performance product. (See related story, 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“It is also clear that the cost of new entry values are outdated and require updates.”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.

September 12, 2014June 15, 2023

Generators: Capacity Performance Unrealistic, Unfair

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.

September 12, 2014June 15, 2023

UTC Trading Falls Following FERC Order

PJM Polling Members on Next Step

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.

September 9, 2014

PJM Drops Plan for Real-Time Reserve Market

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.

September 9, 2014June 15, 2023

FERC Unveils Metrics for Measuring RTO Performance

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.

September 9, 2014

FERC Rejects Duke Affiliates’ Capacity-Sharing Deal

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.

September 9, 2014June 15, 2023

Duke, Dominion Propose 550-Mile, $5 Billion Pipeline for Shale Gas

By Ted Caddell

Duke Energy, Dominion Resources and other partners last week proposed a 550-mile, $5 billion pipeline to carry natural gas from the Marcellus and Utica shale formations to Virginia and eastern North Carolina.

The “Atlantic Coast Pipeline” would carry 1.5 billion cubic feet of gas per day.

Originally, the pipeline was solely a Dominion project. The company announced its intention to build what was then called the Dominion Southeast Reliability Project earlier this year.

Separate from Dominion’s project, Duke and Piedmont Natural Gas solicited proposals in April to bring natural gas into North Carolina. Now Duke, Piedmont and AGL Resources have agreed to join together with Dominion.

Duke will own 40% of the pipeline. Dominion, Piedmont and AGL will own 45%, 10% and 5% respectively.

Six utilities — Duke Energy Carolinas, Duke Energy Progress, Virginia Power Services Energy, Piedmont Natural Gas, Virginia Natural Gas and PSNC Energy — will buy the majority of the pipeline’s capacity in 20-year contracts.

Dominion, which will oversee construction and operation, said it expects to seek FERC approval by 2016. The partnership said it could be in operation by late 2018.

Duke found itself in need of additional sources of gas following its acquisition of Progress Energy and its efforts to reduce its reliance on coal-fired generation. It closed half of its 14 coal-fired plants in the past three years, built five gas-fired plants in North Carolina since 2011 and plans on building another gas-fired plant in South Carolina.

Historically, the Southeast has received natural gas from wells in Louisiana, Oklahoma and Texas. Supply problems and other constraints have sometimes driven gas prices up.

The boom in shale gas production meant the emergence of a northern source of low-priced fuel. The Atlantic Coast Pipeline is the first project designed to deliver those supplies to Virginia and North Carolina. The pipeline will carry gas from the shale fields in Pennsylvania, Ohio and West Virginia.

Dominion says it has already reached agreements with about 70% of the landowners on the route to allow them to survey.

While the partners and elected officials applauded the announcement — Virginia Gov. Terry McAuliffe called it a “game changer” for industry and residential customers — environmentalists are less than enthused.

“Today Gov. McAuliffe has made a huge mistake that harms the environment,” said Mike Tidwell, executive director of the Chesapeake Climate Action Network. “Barely two months after re-launching the state’s climate change commission, the governor has regretfully embraced a Dominion gas pipeline project that threatens to contribute significantly to the climate crisis.”

Tidwell said the pipeline will encourage more fracking and contribute to methane emissions.

“There is enormous leakage from the fracking process, and enormous leakage from the distribution pipelines, where it gets off the main pipeline,” he said Friday. “It gets down to the municipals and the counties, and [those pipelines] are all old and they’re leaking like sieves.”

September 9, 2014

FERC Orders Review of UTC Rules

The Federal Energy Regulatory Commission last week ordered a review of PJM’s rules regarding up-to-congestion transactions (UTCs), saying the RTO may be discriminating in how it treats these and other financial trades.

FERC’s ruling (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. (See MRC Defines UTCs; Adds Bid Limit and FTR Forfeiture Rule.)

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 the forfeiture rule and in the application of uplift charges. It ordered FERC staff to schedule a technical conference on the issue.

PJM’s filing sought to apply the FTR forfeiture — previously applied only to INCs and DECs — to UTCs. The rule is intended to prevent traders from submitting UTCs that boost the value of their FTR. It is applied when those UTCs result in a higher LMP spread in the day-ahead market than in the real-time market.

PJM’s Market Monitor told FERC that PJM’s method for applying the rule to UTCs is inconsistent with how the RTO treats INCs and DECs because it relies upon the contract path, rather than modeled flows.

Trading in UTCs has increased eight-fold since 2010, while INC and DEC trading has dropped by two-thirds. The shift occurred after PJM removed the requirement that UTCs make transmission service reservations.

“The recent growth in UTC transactions, and the corresponding decrease in other virtual transactions, strongly suggests that many UTC transactions may be used in place of virtual transactions. To the extent that a UTC transaction is simply the combination of two virtual transactions that have been connected, it may not be appropriate to treat UTC transactions differently than INCs and DECs in applying the FTR forfeiture rule,” the commission wrote.

“For instance, where a UTC is submitted in combination with INCs and/or DECs and the associated flows on the constrained paths of the combined transaction may be different from those assumed when considering the transactions individually, the tariff may not protect against manipulative transactions.”

The commission also said the forfeiture rule “does not consider trading of INCs/DECs and UTC transactions for the purpose of preventing congestion in order to benefit a short FTR position.”

The commission said it expects to rule on the matter within five months after submission of post-technical conference pleadings. Any refunds resulting from the review will be effective from yesterday, when the notice of the 206 proceeding was published in the Federal Register.

Attorney Ruta Skucas, who represents the Financial Marketers Coalition, said UTC trading volumes will likely drop while the case is pending.

“There will be potentially months of uncertainty” for UTC traders who don’t know if they will be assessed uplift charges, she said in an interview.

September 9, 2014

FERC Questions PJM Capacity Offer Cap

PJM’s Market Monitor overstepped its authority in calculating the maximum price generators can offer into capacity auctions, but the RTO’s Tariff may need to be changed to prevent a windfall to generators, the Federal Energy Regulatory Commission ruled.

The commission ruled in favor of FirstEnergy Solution’s challenge to the Monitor’s method of calculating market seller offer caps. But while FE won its legal argument, the commission also gave weight to arguments by the Monitor and load representatives, who contended FE’s interpretation could allow generators to exercise market power. As a result, the commission ordered a “paper hearing” to determine whether PJM’s Tariff should be changed.

In April, FE asked FERC to rule that PJM’s Tariff requires the use of a generator’s cost-based energy offers in the determination of net projected PJM market revenues, a component used in calculating capacity offer caps.

The Monitor uses the lower of the price-based offer and the cost-based offer submitted by the capacity resource.

The case centered on a dispute over the Tariff’s requirement that projected energy market and ancillary services revenues be “net of marginal costs for providing such energy (i.e., costs allowed under cost-based offers pursuant to Section 6.4 of Schedule 1 of the Operating Agreement) and ancillary services.”

FERC agreed with FE that the Tariff’s use of the abbreviation “i.e.” prevents the Monitor from exercising its discretion in choosing between price- and cost-based offers.

“The term ‘i.e.,’ as defined by Black’s Law Dictionary, is an abbreviation of the Latin id est meaning ‘that is.’ The Tariff therefore is defining the term ‘marginal costs’ to be the cost-based offers under Section 6.4 of Schedule 1,” the commission ruled (EL14-36). “In addition, the Tariff neither mentions a ‘lower-of’ methodology as proposed, nor does it suggest that the determination of marginal cost is subject to the interpretation of the IMM. Indeed, the final interpretation is made by PJM under the Tariff, and our interpretation is also consistent with PJM’s own reading of its Tariff.”

The Monitor said its interpretation was justified because non-zero price-based energy offers that are less than cost-based offers reflect actual marginal cost. Intervenors representing consumers had filed comments supporting the Monitor’s position.

The PJM Industrial Customer Coalition and consumer advocates for six states and D.C. contended a FE victory “would result in a direct transfer of potentially billions of dollars from customers to sellers.” (See Billions at Stake in Capacity Market Challenge.)

Because of those concerns, the commission said, the Tariff’s provisions for the calculation of projected market revenues “may be unjust and unreasonable.”

The commission ordered PJM to file a brief defending the current language within 60 days. Reply briefs will be due 30 days after PJM’s brief.

September 9, 2014

PJM IMM Questions MISO Cost Recovery Ruling

By Michael Brooks

PJM’s Market Monitor has weighed in on a MISO dispute over whether generation owners can be compensated for their plants’ sunk costs when the plants are prevented from retiring in order to maintain grid reliability.

In July, the Federal Energy Regulatory Commission found that MISO’s Tariff rules concerning system support resources (SSRs) were unjust and unreasonable because they did not compensate generation owners for their SSR units’ fixed costs, only their going-forward costs. Under MISO’s Tariff, the ISO may designate a plant that is scheduled to be retired or suspended as an SSR if it finds that the plant is necessary to main grid reliability.

The PJM equivalent to the SSR is the reliability-must-run (RMR) unit.

In a filing last month (EL13-76), PJM’s Market Monitor asked FERC to clarify its ruling.

“If by ‘fixed costs,’ the commission only means fixed costs incurred specifically to provide SSR service, the Market Monitor requests clarification on that point,” the Monitor said. “The Market Monitor respectfully urges that if a finding that sunk fixed costs should be recovered through SSR service rates was intended, that such a finding be reversed.”

The Monitor argued that generators scheduled to retire were likely not recovering all of their sunk costs when they were operating. Allowing a generator to recover sunk costs through the market in a SSR agreement would create the unintended incentive for generators to retire their units prematurely, the Monitor said.

“The goal of an SSR service agreement should not be to provide a windfall that the market would not otherwise provide,” the IMM said.

Instead, the IMM recommended that MISO provide an incentive rate for SSR units, as PJM does for its RMR units.

FERC’s ruling stems from a July 2013 complaint by Ameren, which at the time owned the Edwards coal-fired plant near Peoria, Ill. After Ameren decided to retire the plant’s 90-MW Unit 1, MISO designated it as an SSR.

Ameren had asked FERC to rule that the definition of “going-forward costs” in SSR agreements include fixed costs and requested that about $12.8 million be included in the Edwards SSR agreement. Illinois Power Holdings, a subsidiary of Dynegy, bought the plant last December and asked for another $5 million.