The Federal Energy Regulatory Commission approved PJM’s plan for selecting transmission projects that can easily and cheaply resolve constraints in Locational Delivery Areas (LDAs).
The new rules require PJM staff to identify — before posting the planning parameters for each Base Residual Auction — Locational Deliverability Areas in which the Capacity Emergency Transfer Limit is less than 1.15 times the Capacity Emergency Transfer Objective (See Quick Fix Transmission Upgrades Ok’d).
Upgrades that increase the ratio to more than 1.15 would be added to the Regional Transmission Expansion Plan (RTEP) if they cost less than $5 million and can be completed prior to June 1 of the Delivery Year. Projects that duplicate upgrades whose cost is already assigned to an interconnection customer would be excluded.
Such projects are unlikely to be common. PJM told the commission that it had identified no circumstances that would justify such projects in the last three years.
FERC approved the proposal over the objections of Utility Risk Management Corp. (URMC) and NextEra (ER14-456).
URMC said the proposal would hurt merchant transmission developers by allowing PJM to supplant merchant upgrades. NextEra argued that the proposal would disguise price signals and reduce transparency and innovation.
FERC said the narrow scope of these quick-fix projects was enough to alleviate these concerns and ensure consistency with Order 1000.
FERC endorsed PJM’s contention that, in relieving minor constraints that are unlikely to return in future years, it prevent misleading price signals.
As a condition of the approval, FERC required that PJM post an annual list of quick-fix proposals and recommended that the RTO and its stakeholders devise operational procedures in case such a project cannot be completed by June 1 of the relevant delivery year.
Below is a summary of the six requirements included in the draft reliability standard for physical security of the grid.
Transmission owners should perform a risk assessment of transmission stations and substations to determine which ones, if disabled or damaged, could result in “widespread instability, uncontrolled separation, or cascading within an Interconnection.” Assessments should be repeated every 30 months if such a vulnerability is identified and every 60 months if not.
Transmission owners should have an unaffiliated third party verify the risk assessment. Such third parties can be a registered planning coordinator, transmission planner or reliability coordinator, or “an entity that has transmission planning or analysis experience.”
Transmission owners with stations or substations identified under Requirements 1 or 2 that are not under their direct control must notify the operator of a primary control center that does control the stations of their critical status.
Operators of stations, substations or primary control centers identified as critical under Requirements 1 through 3 must conduct an evaluation of potential threats and vulnerabilities of those facilities. The evaluation must consider the characteristics of the facilities and any prior history or attack of similar facilities, and incorporate any threat intelligence provided by NERC, law enforcement or other authorities.
Operators of facilities identified during the threat analyses must develop within 120 days a physical security plan for the facilities, incorporating security measures, law enforcement contact information, a timeline for implementing the security plan and ways to conduct ongoing threat evaluations.
Transmission owners and operators must have a third party evaluate the threat analysis in Requirement 4 and the security plan developed in Requirement 5. The evaluation must be completed within 90 days of the security plan completion, and any changes suggested by the third party must be performed within 60 days.
PJM last week withdrew a proposal to develop a generic transition mechanism to hold capacity providers harmless for future rule changes.
The RTO’s proposed problem statement and issue charge was withdrawn from the agenda of the Markets and Reliability Committee without explanation. There was no indication why the issue was withdrawn or whether it will be added to a future agenda.
The proposal was prompted by the transition mechanism approved by members to protect generators whose installed capacity ratings are reduced by seasonal verification tests.
The Markets and Reliability Committee approved the following Tariff and Operating Agreement revisions last week:
Clarifications to the Tariff and OA giving generators providing Tier 2 synchronized resources the ability to aggregate these resources in order to avoid retroactive penalties for failure to respond appropriately when called. New language will also be added to Manual 11: Energy & Ancillary Services and Manual 28: Operating Agreement Accounting. Aggregation will not be used in calculating Tier 2 Synchronized Reserve credits; each resource will continue to be credited independently.
Revisions to the Tariff to reflect current PJM practices regarding credit available for virtual transactions. PJM instituted the policy as the result of a FERC Order in 2004 but failed to make accompanying changes to the Tariff. These revisions also correct for changes in credit policy since 2004 (e.g., working credit limit discount is now 25%, not 15%).
Clarifications to the Tariff and OA on regulation shoulder hour lost opportunity costs (LOCs). As a result of a review, PJM discovered that the documents didn’t adequately describe the calculation of the deviation between the regulation set point and the expected output of each regulation resource.
Changes to the Tariff and OA reflecting PJM’s change in mailing address to: PJM Interconnection, L.L.C. 2750 Monroe Blvd., Audubon, PA 19403.
The MRC also approved the following manual changes:
Manual 13: Emergency Operations — The changes will allow declaration of Cold Weather and Hot Weather alerts several days in advance instead of the day before.
Manual 18: PJM Capacity Market — Conforming the manual to recent FERC orders, including seasonal verification testing and Capacity Import Limits effective with the 2017/2018 delivery year. (See related story, FERC Clears Capacity Import Limits.)
The Members Committee endorsed the following consent agenda items last week:
Revisions to PJM’s Tariff and Operating Agreement to clarify agreements and transactions to which PJM Settlement, Inc. is not a party.
Operating Agreement and Tariff revisions to effectuate the eSuite application name changes (i.e., changing eSchedules and EES to InSchedule and ExSchedule, respectively). Proposed improvements to eSuite applications are slated to continue through 2015.
NRC Gives Exelon’s Limerick Extension for Fukushima Fix
Limerick (Source: Exelon)
The Nuclear Regulatory Commission granted Exelon’s request for an additional two years to make upgrades to the reactor buildings at its Limerick Nuclear Generating Station. The NRC in 2012 ordered Exelon to take steps to prevent hydrogen buildups similar to what occurred during the Fukushima disaster in Japan in 2011.
The Limerick reactors share some design similarities with the Japanese units. The NRC ordered installation of a “hardened wetwell vent” system to extract combustible gas from building up and possibly exploding. “The installation of such vents is one of our post-Fukushima requirements,” said NRC spokesman Neil Sheehan. Exelon will have until the end of a refueling outage in spring 2018 to complete the work at Unit 1 and until the end of a refueling outage in spring 2017 to complete the work at Unit 2, the NRC said.
The higher water temperatures of Long Island Sound aren’t too high for the Millstone nuclear plant to use, according to the Nuclear Regulatory Commission. The NRC granted Dominion’s Millstone Unit 2 a license amendment to allow operation if its cooling water, drawn from the Sound, rose in temperature to 80 degrees. Unit 2 was forced offline for 12 days in 2012 when Sound water temperatures rose above the then 75-degree limit. The NRC is considering a similar amendment request for Millstone Unit 3.
“We’ve seen a long-term trend over the last 40 years of Long Island Sound temperatures steadily increasing,” Millstone Spokesman Ken Holt said. In 2012, the average temperature in the Sound near the Unit 2 intake pipe was about 77 degrees, he said. The company believes the five-degree margin will be sufficient to allow it to continue operations without costly unplanned shutdowns, he said. “We think we can stay well within the limit,” he said.
Additional natural gas pipeline capacity is coming to the Southeast with the Federal Regulatory Commission’s approval of an application for the construction of Transco’s Mobile Bay South III Expansion project. Williams Partners LLP said the project is expected to be completed by spring 2015.
Stakeholders split last week over a PJM proposal to change how the RTO captures the cost of deploying additional reserves during extreme weather.
PJM’s Lisa Morelli presented a first read of the proposal — which is intended to capture operators’ reliability actions in Locational Marginal Prices rather than uplift — at last week’s Markets and Reliability Committee meeting.
Stakeholders representing generation expressed support for the proposal while those representing load said they feared it could lead to unduly conservative operations and higher overall costs.
It would increase day-ahead and real-time reserve requirements when hot- or cold-weather alerts or max emergency generation alerts are issued for the RTO or for either the Mid-Atlantic-Dominion or Mid-Atlantic regions.
“On a day like this there’s a ton of uncertainty,” said PJM Executive Vice President for Operations Mike Kormos, citing generator performance and forecasts for weather, load and interchange. “We can’t roll the dice and hope things go away.”
The adder for day-ahead reserves would be set at 3% of forecasted load, boosting reserves from 6.27% to 9.27%. The real-time reserve adder would be equal to the default Mid-Atlantic-Dominion (MAD) synchronized reserve requirement of 1,300 MW.
The increases would be implemented only if operators believe the additional resources can be scheduled without causing operational problems. The real-time adder would be reduced to 50% of the MAD synchronized reserve requirement or lower if the higher amount becomes problematic.
The increased reserves would be reflected in market clearing engines, ensuring that the costs go into LMPs and not uplift.
“This has been a long time coming,” said PJM Vice President for Market Operations Stu Bresler. “… This is very important to us.” Bresler said the best solution — changing reserves in real time — would be more complex and less transparent.
Ed Tatum, of Old Dominion Electric Cooperative, called the proposal “reactionary.”
“Sixteen years and 24 days into this LMP business … we keep on doing non-market things,” he said. “… We are moving further and further away from the concept of a market. We’re taking it more into an administrative construct.”
David “Scarp” Scarpignato, of Direct Energy, said the proposal could lead to overly conservative operations and increase costs to load. PJM already carries reserves equal to 150% of the largest single contingency, while other regions use only 100%, he said.
“We have very big problems with this,” he said. “PJM already has more conservative synchronized and primary reserve targets than other areas.”
Jason Barker, of Exelon, said Scarp had mischaracterized the PJM proposal. Last July, Barker said, PJM dispatched demand response at $1,800/MWh and Exelon’s peaking generators at “hundreds of dollars” at a time when LMPs were only about $60/MWh. “All of these [costs] were paid through uplift,” he said.
PJM, which wants to implement the changes in time for this summer, will bring the proposal to votes at the MRC and Market Implementation Committee next month. It was developed during meetings of an MIC subgroup on Energy/Reserve Pricing & Interchange Volatility.
At a meeting of the subgroup yesterday, PJM officials said that logistical problems prevented them from producing simulations to gauge the impact of the changes.
Members agreed to consider changing the $1,000/MWh offer cap last week following a debate over whether unusually high gas and electric prices during January were a fluke or a sign of winters to come.
The Markets and Reliability Committee approved PJM’s proposed problem statement, which says stakeholders should consider lifting the cap because this winter’s extreme conditions had for the first time put the limit at odds with rules requiring capacity resources to offer their output into the day-ahead energy market. The accompanying issue charge was also approved.
The initiative passed with 27 abstentions and 11 “no” votes. Susan Bruce cast 10 of the no votes and four abstentions on behalf of the PJM Industrial Customer Coalition. Bruce said the coalition had never voted against a problem statement before.
“We are perhaps rushing to judgment,” she said, noting that PJM had not released all of the results of its analysis of the winter. “… As I sit here today, I don’t know what I don’t know.”
The measures were amended to include an Oct. 31 target date for completion, in order to facilitate a Federal Energy Regulatory Commission order by the end of the year. Also added was the Market Monitor’s request to clarify the offer cap’s application to incremental, startup and no-load costs.
FERC Orders
On Jan. 24, FERC granted the RTO’s request for a waiver allowing make-whole payments for generators with operating costs above the $1,000 cap. PJM said the waiver was necessary to allow some gas-fired generators to cover marginal costs that hit $1,200/MWh in late January, as spot gas prices spiked to $140/mmBtu.
The January order allowed PJM to fund the make-whole payments through uplift charges. On Feb. 11, FERC granted a second waiver eliminating the cap through March 31, allowing high-cost generators to set Locational Marginal Prices.
FERC lifted the cap over the objections of consumer advocates, state regulators and others, who said allowing the RTO’s most inefficient generators to set clearing prices would provide a windfall to the vast majority of generators with costs well below $1,000. (See Stakeholders Preview Offer-Cap Debate.)
The proposal to consider changing the cap appeared to have the support of generators. Jason Cox, of Dynegy, praised PJM for being “proactive.”
But most of the comments came from those representing load.
Will High Prices Repeat?
“It’s not exactly clear to us that this sort of issue is going to happen over and over again,” said Raghu Sudhakara, of Rockland Electric Co.
“If the purpose is to pull the wool over the eyes of people … and finagle something through without us understanding it, I have a problem with that,” said Gloria Godson, of Pepco Holdings Inc., who insisted the stakeholder process include an examination of high gas prices. PHI abstained on the vote.
Carl Johnson, who said he considered voting no, ultimately cast 15 abstentions on behalf of the PJM Public Power Coalition. “It’s seems [PJM] is taking everything in the FERC order and trying to put it into the Tariff,” he said. “We don’t think having to get a waiver is always a bad thing.”
He also said that the actual impact of the FERC waivers — which yielded about $9,000 in make-whole payments to generators whose production costs went above the offer cap — might not warrant months of prickly debate.
Walter Hall, of the Maryland Public Service Commission, said he was concerned that PJM was “somewhat telegraphing the result you are expecting.”
Not Hypothetical
Bob O’Connell, of J.P. Morgan Ventures Energy Corp., warned members that a no vote would not end efforts to lift the cap.
An MRC rejection “doesn’t prevent members from creating a user group and rushing this through an alternative stakeholder process that may disenfranchise certain members,” O’Connell said. “I suspect there are [at least] five members sitting at this table today that would want to move this forward.”
Steve Lieberman, of Old Dominion Electric Cooperative, said ODEC would have voted no but feared rejection of the measure would lead PJM to make a unilateral section 205 filing with FERC to lift the cap.
Executive Vice President for Markets Andy Ott indicated Lieberman’s concern was well founded, saying PJM needs to act.
“This is not theoretical; this is an issue where we had [generator] costs over $1,000,” Ott said. “No matter what happens at FERC [with relation to future gas prices], we could have gas prices where the $1,000 offer cap doesn’t work. We feel it needs to be addressed by next winter.”
ODEC’s Ed Tatum lamented that efforts to lift the offer cap were the latest of recent PJM initiatives — following changes to limit imports and demand response in the capacity market — that could increase prices for load.
In a discussion over which stakeholder group should address the issue, Tatum argued in favor of the MRC, noting that it involves reliability. He expressed reservations about the Capacity Senior Task Force, which he said had not been a friendly venue for load.
“This RPM [Reliability Pricing Model] stuff has not worked out well for the left side of the room,” he said, referring to where representatives of cooperatives, industrial customers and public power were seated. “We’re not getting a lot of love.”
The committee voted to assign the issue to a new task force reporting to the MRC.
Stakeholders last week approved draft regulations to protect the electric grid from physical threats even as many criticized the rules as rushed and poorly defined.
The draft regulations, drawn up by a North American Electric Reliability Corp. working group of 11, are now being considered by the NERC board. NERC must submit proposed regulations to the Federal Energy Regulatory Commission in June. FERC has scheduled a technical conference June 10 to discuss “policy issues related to the reliability of the Bulk-Power System” at which the NERC filing is likely to be a centerpiece.
The plan won 82% approval in polling of NERC members last week. Among PJM members, Duke Energy, Exelon, FirstEnergy and Dominion all said they support the draft standards, while AEP voted no.
“Are we being overly reactive?” a stakeholder from AEP asked, according to a summary of feedback to the draft regulations that was compiled by NERC. “Poorly executed, these standards could carry astronomical … costs.”
“We need to spend time to get this right and not rush something through,” a stakeholder from the Nebraska Public Power District wrote. “This expedited standard development has the potential to derail our entire NERC standard development process.”
The regulations are in response to concerns resulting from the sabotage of a PG&E Corp. substation last year. Under pressure from Congress, FERC on March 7 ordered NERC to develop standards to address physical attacks within 90 days. (See FERC Orders Rules on Grid’s Physical Security.)
Critical Substations
Dominion Virginia Power plans to spend as much as $500 million to upgrade security at its substations, including the installation of anti-climb fences, as in the simulation above. (Source: Dominion)
The NERC draft calls for utilities to provide protection for “critical” substations, but it allows each utility to determine what substations are critical. The rules call for third-party review of critical facilities but would allow utilities to act as each other’s third party. (See related story, NERC Draft Rules for Physical Security.)
The draft rules don’t require hardening critical substation sites with blast barriers or other defenses, as some critics have suggested.
Several stakeholders were critical of the short time FERC gave NERC to comply. Others said the standards should apply not just to transmission owners and operators but also to transmission planners, reliability coordinators and generation owners and operators.
Still others said the standards were too loosely defined. “As described, the objective of protecting critical facilities of the [Bulk Electric System] is stated too broadly and it is not apparent what countermeasures would be considered adequate or sufficient,” wrote the Bonneville Power Administration.
Brightline Criteria
Colorado Springs Utilities recommended a “brightline criteria” for the facilities covered by the standards, “based on either the Transmission Planning Standard TPL-004a [System Performance Following Extreme Events Resulting in the Loss of Two or More Bulk Electric System Elements] or identification of the largest single contingency for each interconnection. If we need a single number, [include] only facilities that provide or control over 3,000 MW of generation or transmission operating at 300 kV and above.”
AEP also questioned the proposed definition of critical facilities. “FERC and NERC have implied that the number of critical facilities identified in this process will be relatively small — fewer than 100 of the 55,000 transmission stations dispersed throughout the country. However, for previous `critical asset’ determinations requested by NERC, AEP has already identified almost that many just on our own system. This would indicate we are starting over with the definition of critical facilities, which is counter-intuitive if not counter-productive.”
One member, from the Southwest Power Pool, noted that NERC’s existing definition of Critical Assets is scheduled to be retired in 2016. “How does one then determine the list of ‘critical’ facilities if that definition no longer exists?” that member said.
Several stakeholders referred to a 2013 FERC power flow analysis on the 30 most critical substations nationwide. The analysis, which was leaked to The Wall Street Journal in March, reportedly concluded that the Eastern and Western Interconnections and ERCOT could be shut down for weeks or months if only nine of the substations were sabotaged.
“If a list of the most critical substations exists, why are we trying to develop a new process to determine the list?” a stakeholder from the Nebraska Public Power District asked. “I feel we have been blindfolded and put into a room and told to hit a small target with a dart and we don’t even know which wall or direction to throw the dart.”
Cost Concerns
AEP echoed concerns about the cost of the rules. The new standards, AEP wrote, “could result in massive changes, bringing excessive additional costs with no guarantee of desired outcomes … While we need to make whatever investment is necessary to adequately protect the grid, we also need to be responsible stewards of the grid and our ratepayers’ pocket books.”
In response to criticism of the draft rules cited in a Journal article April 17, NERC issued a statement defending the regulations and the process used to develop them.
“Standards are one piece of this complex, dynamic endeavor of providing a comprehensive approach to reliability,” NERC said. “NERC also has various other tools to fulfill this mission, including guidelines, training, assessments and alerts. This multi-pronged approach has resulted in a secure and reliable bulk power system for North America.”
In a win for PJM generation owners, the Federal Energy Regulatory Commission approved a rule change that will reduce capacity imports and likely increase clearing prices.
The commission approved PJM’s capacity import limits over the objections of consumer advocates, MISO’s market monitor and others who said it will unfairly raise prices and restrict competition (ER14-503). The new rules create five export zones with a combined limit of 6,499 MW for the May Base Residual Auction, a 17% reduction from what cleared in the 2013 auction.
FERC said the limits were based on “a reasonable methodology” to address the risk that imports may be curtailed by transmission providers outside of PJM. The commission said the methodology is an improvement over the current system, in which PJM assesses import capability by evaluating individual requests for long-term transmission service.
It rejected calls from intervenors to modify PJM’s proposal, noting that the commission’s role in a section 205 proposal is to determine whether PJM’s proposal is just and reasonable, “not to determine whether alternative proposals are more or less reasonable.”
AMP, MISO Protests Rejected
The commission rejected complaints by American Municipal Power Inc. (AMP) and MISO that the proposal gave PJM too much discretion.
AMP contended PJM’s assumption that no redispatch will be provided to support firm deliveries was contrary to MISO’s practices and will result in lower limits than are necessary to address PJM’s reliability concerns.
MISO said the proposal gives PJM too much discretion in how it sets the limit. The commission said it was satisfied by PJM’s promise that it will continue to coordinate with MISO on modeling used to calculate the limits.
Commissioner John Norris filed a concurring statement warning that prices could rise if PJM is overly conservative in setting the limits. “I urge PJM and its stakeholders to continue to work towards ensuring that the calculation of the capacity import limit does not unnecessarily limit the most efficient utilization of available resources,” he wrote.
Monitor’s Proposal Rebuffed
Some PJM utilities and the Independent Market Monitor had asked the commission to require that all capacity resources be pseudo-tied, have confirmed, firm long-term transmission service and be subject to the same capacity must-offer requirement as internal resources. The commission said those conditions — which PJM proposed for resources seeking an exemption from the import limits — would limit competition from external resources without enhancing reliability.
The commission also rejected a challenge by consumer advocates who said the limit should not reflect a 3,500-MW deduction for the capacity benefit margin — a reservation for imports of energy during emergencies. The commission noted that the capacity benefit margin allows PJM to operate with a smaller reserve margin, reducing its purchases in the capacity auctions.
“If the Capacity Import Limit is not reduced by the capacity benefit margin, the emergency-only reliability purpose of the capacity benefit margin could be compromised because the total quantity of megawatts of external capacity available for emergency assistance may be overstated,” the commission said.
Regulators, consumer advocates and the Market Monitor last week urged the Federal Energy Regulatory Commission not to change a crucial rule for PJM’s upcoming capacity auction, warning that it would allow generators to exercise market power.
FirstEnergy Solutions Corp.’s request to change how PJM calculates the maximum price generators can offer into capacity auctions “would result in a direct transfer of potentially billions of dollars from customers to sellers,” said the PJM Industrial Customer Coalition and consumer advocates for Maryland, Pennsylvania, Delaware, New Jersey, West Virginia, Illinois and the District of Columbia.
In separate filings, the Ohio Consumers Counsel and the Organization of PJM States (OPSI), representing state regulators, also weighed in against FirstEnergy’s request.
PJM, however, said it agrees with FirstEnergy’s interpretation of its Tariff and urged the commission to approve the company’s request. Also siding with FE is the Electric Power Supply Association and the PJM Power Providers Group.
Declaratory Order Sought
On April 7, FE filed a petition for a declaratory order (EL14-36), asking FERC to rule that PJM’s Open Access Transmission Tariff requires the use of a generator’s cost-based energy offers in the determination of net projected PJM market revenues. Granting the request could result in higher Market Seller Offer Caps, likely increasing auction revenues for FE and other generators.
FE asked the commission for an expedited ruling by May 9, in time to set the rules for the Base Residual Auction that begins May 12.
FE’s request would change methodology the Monitor has used since 2007, which selects as an input whichever is lower, the unit’s market-based offer or the cost-based offer.
No Emergency
Opponents said there was no reason for FERC to rush to rule in the dispute.
“FES could have filed its Petition months (or perhaps years) ago,” said the Ohio Consumers Counsel. “Instead, FES chose to file five weeks before the BRA.”
Their colleagues in other states consumers agreed. “There is more potential harm in expediting a decision than in carefully reviewing the issue,” said the consumers’ filing.
State regulators said altering the methodology would require a Tariff change and thus should be subjected to PJM stakeholder review.
Calculating Marginal Costs
Because existing generators possess market power, PJM requires mitigation in the form of the Market Seller Offer Price (MSOP), a cap on the price they can seek in the capacity auction.
The MSOP is intended to represent the solution to the so-called “missing money” problem. It is calculated as the difference between the unit’s Avoidable Cost Rate — the cost of running the plant for another year — and its projected net revenue.
Net revenue is calculated as total energy and ancillary services revenues less marginal costs. It is the calculation of marginal costs that is at the heart of the dispute.
The Market Monitor has always calculated marginal cost as either the unit’s market-based offer or its cost-based offer, whichever is lower. The latter offer is a price cap designed to counter market power in the energy market.
“Cost-based” is a misnomer, according to the Monitor, because it can include a 10% “adder” to actual costs.
In practice, generators often make market-based offers that are below their cost-based offers — which the Monitor says better represents their marginal costs.
“Sellers want their unit dispatched when the market price (Locational Marginal Price (LMP)) is greater than marginal cost. Accordingly, a non-zero offer lower than the offer cap is the best available evidence of what the seller believes is its marginal cost,” the Monitor wrote in its filing last week.
FirstEnergy says it is unfair to use the lower offers in the MSOP calculations: Generators may offer into the energy market at prices below their marginal costs because they want to continue running regardless of the clearing price.
“The operational characteristics of some power plants require this strategy at times to maximize efficiency and to reduce long-term costs. For example, a unit might need to avoid cycling on and off in succession to prevent expensive tube leaks or other associated repairs, which in turn could result in forced outages, performance penalties in the capacity market, and obligations to pay for deviations in the energy market. Other units also may need to keep producing power to avoid incurring penalties under `take or pay’ fuel contracts,” FE said.
“By choosing to operate in some hours by generating when energy prices are below a plant’s marginal cost of production, the plant operator is making a rational decision to absorb a small loss to avoid an even greater loss caused by the inefficient cycling of the plant that would otherwise occur.”
Tariff Definition
PJM, in a filing last week, said it agrees with FirstEnergy. “Use of cost-based offers (and not the lower of price-based and cost-based offers) is required by the Tariff. Indeed, PJM could not remain complaint [sic] with its Tariff if it were to read unstated provisions into the rule to effect the outcome desired by the [Monitor].”
What neither PJM nor FirstEnergy told FERC, however, is why it took them so long to come to this conclusion.
Impact of change
The Monitor said FirstEnergy’s petition was filed after it rejected FE’s proposed offer price caps for certain of its coal-fired generating units. “FirstEnergy offers no attestation here or elsewhere that its price-based offers reflect anything other than FirstEnergy’s calculation of the actual marginal costs of the FE Units,” the Monitor said. “FirstEnergy’s behavior has been consistent with the behavior of other market participants who have for years accepted that their non-zero price offers lower than their offer price caps are the best indicator of their actual marginal costs.”
The Monitor said FirstEnergy’s offers could set or influence market prices. “For example, there is a possibility that the level of Sell Offers submitted for certain of the FE Units will influence whether specific zones clear as Locational Deliverability Areas (LDA) with price separation.”
The Monitor said it agrees that capacity market prices have been suppressed and noted recommendations it has made to address the issue. But it said the company’s attempt to upend long-standing practice is improper.
The Monitor said it discussed its method of calculating net revenues with FirstEnergy in November 2012 and again early this year.
“It is implausible that FirstEnergy did not calculate its own net revenues for prior RPM auctions. Yet FirstEnergy has never raised this issue before,” the Monitor said. “Any missing money problem faced by FirstEnergy did not emerge for the first time in the last thirty days.”
