Proposals to eliminate the impact of curtailments on wind generators’ capacity calculations create many losers as well as winners, according to data presented to the Planning Committee Thursday.
Two proposals are being considered under a problem statement approved in April to protect intermittent generators from being assigned artificially depressed capacity values as a result of curtailments directed by PJM.
Under current policy, when wind generators are curtailed by PJM for any portion of a peak summer hour, the hour is excluded from the generator’s capacity credit calculation.
PJM staff conducted an analysis of the two alternative calculations using data for summer 2012, when 33 of 50 wind generators had at least one curtailment.
Alternative 1
Alternative 1 removed from the calculations only the five-minute periods in which a curtailment occurred rather than the full hour, as in current practice.
It increased capacity factors for 21 of the 33 units that experienced curtailments (64%). Changes ranged from an increase of 2.6 percentage points to reductions of almost 2 points with a median increase of 0.2 points.
The biggest increases in capacity factors went to units curtailed most frequently — a 2 percentage point boost for most units with more than 150 curtailed five-minute periods.
Alternative 2
Alternative 2 reduced capacity factors for 21 of 33 curtailed generators. It estimates what the generator’s output would have been during curtailment by interpolating data between the five-minute periods before and after the interruption.
Alternative 2 showed a more normal distribution of impacts, with little correlation to the number of curtailment periods. It reduced capacity factors by a median of 0.2 percentage points, with some units losing almost 2 points while others increased by 2 points.
No Robust Solution
Steve Herling, PJM vice president of planning, said PJM limited the analysis to 2012 because data from prior years was not as reliable or complete.
“With only one year of data it’s going to be very difficult to come up with a solution that’s really robust,” Herling said. “That doesn’t mean we shouldn’t try to do something.”
The committee will be asked at its next meeting to decide whether to choose one of the alternatives or to leave the methodology unchanged.
PJM’s current procedure uses hourly integrated metered data. The two alternatives would use five-minute data from PJM’s state estimator. Because the hourly integrated data is more accurate, PJM plans to continue to use that data for the units with no curtailments, said PJM’s Tom Falin.
An increase in the dispatch of gas-fired units in east PJM reduced west to east congestion in PJM’s 2013 market efficiency analysis, officials told the Transmission Expansion Advisory Committee Thursday.
“Fuel prices were the main driver” in the analysis, said PJM’s Tim Horger. Otherwise, Horger said, “results were very similar to” the 2012 analysis.
The analysis looked at study years 2014 and 2018 to determine whether projects in the Regional Transmission Expansion Plan should be accelerated or modified, and 2017, 2020 and 2023 to consider the addition of new projects to the RTEP.
The study assumed:
Coal prices increase from $2.60/MMBtu in 2013 to $3.75 in 2023, a 4.4% annual increase.
Natural gas prices increase from $3.68 to $6.50/MMBtu, a 3.1% annual increase.
Peak demand increases 1.4% per year, from 154,712 MW in 2013 to 176,548 in 2023.
PJM will post case files for all study years. Accessing the files requires authorization to access Critical Energy Infrastructure Information (CEII) and a license from Ventyx for powerbase data.
NEWARK, NJ — Would the PJM model work for the natural gas industry? Charles River Associates’ Robert Stoddard thinks it’s worth a try.
Stoddard told the Energy Bar Association’s Northeast Chapter Wednesday that a Regional Pipeline Organization, or RPO, could help address the pipeline capacity shortage that has complicated the growing interdependence between the natural gas and electric industries.
He said the current $1.65/MMBtu basis spread between Henry Hub and the Algonquin citygates is evidence of the need for an additional interstate pipeline serving the Northeast. But pipeline operators cannot build without firm supply contracts – which few gas-fired generators have been willing to sign.
“Right now we have no one who is responsible for thinking about a plan” for pipeline expansion, he said. “We are piggybacking on pipelines that were built for [local distribution companies] … How do we expect that to work?”
While the other speakers on the panel agreed on the need for more pipeline capacity, none embraced Stoddard’s RPO proposal.
Richard Kruse, who heads regulatory affairs for interstate pipeline operator Spectra Energy Transmission, said his company has been serving the industry for 50 years. “And we did it,” he said, emphasizing the point, “without an RPO.”
RPO Not Suitable
Kruse said the RPO concept is not suited to the nature of the natural gas industry and would eliminate competition among pipelines for expansion opportunities.
“We’re not regional pipelines, we’re linear pipelines. You’re talking about breaking up companies and remolding them,” he said. Spectra owns three pipelines that are more than 1,000 miles long, including Texas Eastern Transmission, which spans 9,200 miles from the Gulf Coast to Northeast.
John P. Rudiak, senior director of energy supply for local distribution companies Connecticut Natural Gas Corp. and Southern Connecticut Gas Co., also was cool to the idea.
“An RPO might have been credible a year ago. That’s not the case now,” Rudiak said, explaining that the gas industry has been increasingly talking to ISO New England, which has more than 500 wholesale market participants and more than two dozen stakeholder committees and working groups. “[The gas industry is] not very impressed with the workings of the ISO. It is a process that’s very cumbersome to say the least.”
Market Disconnects
Stoddard said the varying tariff rates in the pipeline industry distorts least-cost dispatch in electricity. “Instead of dispatching the unit with the lowest carbon footprint we’re dispatching those that happen to have the cheapest gas,” he said.
Stoddard said gas-fired generators are reluctant to commit to firm contracts because it is very difficult for individual generators to forecast how often they will be dispatched, and thus how much gas they will burn. Because so many gas-fired generators have similar specifications and cost profiles, he said, “which one gets committed is sort of like drawing a lotto card.”
Communication Gaps Not the Issue
What the speakers did agree on was that the challenge is one of infrastructure and not one of a lack of communication between the gas and electric industries.
Kruse said the two industries have been increasing communication in the Northeast since the 2004 Boston “Cold Snap,” when the coldest January in 116 years pushed the electric and natural gas systems to record demand. “Never have so many talked about so much and accomplished so little,” he said, adapting a quote from Winston Churchill.
Kruse said data requests sent to ISOs by the Federal Energy Regulatory Commission last week “could have [been] written … a year ago, two years ago, in 2004.”
Matthew J. Picardi, vice president of regulatory affairs for Shell Energy N.A.’s East region, said there’s no need to move to a common gas-electric trading day, as some have urged, though he said there could be benefits to moving up the gas day — which starts at 9 a.m. Central time — by an hour. The real issue, he said, is “power markets must support costs for more gas infrastructure.”
Too Much Information?
Kruse expressed concern that the gas industry could be providing too much information to grid operators.
“The ISO is a market player that actually decides who uses gas,” he said. “How much communication with ISOs [is permissible] before it becomes an undue preference to the electric industry versus our other customers?”
To Build or Not?
While all of the speakers on the panel called for more pipeline construction, FERC Commissioner John R. Norris, in separate remarks to the EBA, called for a long-term view.
He cited a projection that cutting CO2 emissions 80% by 2050 — a target the U.S. agreed to at the 2009 G8 summit — will require eliminating gas as a baseload fuel. Gas-fired generation would be limited to load following in support of variable generation.
Such a shift would conflict with the economics of the pipeline industry, which expects to recover its investment in new pipeline capacity over 30 years or more. “Is [a new pipeline] smart long-term energy planning?” he asked.
PJM “will err on the side of caution” in disclosing details from transmission developers’ project proposals, RTO officials told the Planning Committee Thursday.
On April 29, PJM announced opened its first “proposal window” under the Federal Energy Regulatory Commission’s Order 1000, which opens transmission projects to non-utility transmission developers. PJM will accept proposals through June 28 to correct stability issues on Artificial Island in Hancocks Bridge, N.J., the site of the Salem and Hope Creek nuclear plants.
Steve Herling, PJM vice president of planning, said the RTO will release “no brainer information” on proposals submitted in response to the Artificial Island needs and future proposal windows.
Such information would include “a line from A to B, impedance modeling, so people can analyze [the proposals],” Herling said. “We won’t put out right of way information. You’d get the public all stirred up that `we’re looking at your property.’”
Prequalification
Order 1000 eliminated incumbent utilities’ Right of First Refusal on construction and operation of new transmission lines, opening the business to competition from independent transmission developers. Incumbents will retain the right to construct “upgrades” to their existing facilities.
PJM has created a two-step process for complying with Order 1000. First, potential transmission developers must be prequalified based on their ability to construct and maintain a generic transmission project.
Those prequalified will be eligible to submit solution packages in response to proposal windows like that for Artificial Island.
PJM officials said Thursday that seven developers have submitted prequalification packages with more applications expected shortly.
Herling said the application packages will be posted publicly after PJM determines which ones are prequalified. “There has to be some due process to challenge the decisions we’ve made,” he said.
Constructability Template
PJM has created a template to evaluate responses to its proposal windows. The RTO plans to hire independent consultants to validate developers’ cost estimates and identify potential regulatory risks, such as the likelihood of obtaining siting for rights of way.
“If you have half the right of way in hand, that certainly will have an impact on cost and regulatory risk and would probably affect construction time,” Herling said. “To give you credit, we would have to disclose some information. We don’t have to talk about individual pieces of property you have.
“If it becomes obvious that we’re relying heavily on one piece of information we’re going to have to make it public — and you might still not get chosen,” he continued. “… We’ll have to make sure it’s transparent and above board to defend ourselves against challenges.”
The Market Implementation Committee Wednesday approved changes to Manual 11 affecting regulation rules, hydropower generators, station manning and shortage pricing. The changes go next to the Markets and Reliability Committee.
Reason for changes: Clarifications, error corrections and changes to conform with other manuals.
Impact:
The changes:
Clarify and add conforming language for regulation rules:
Resources cannot clear for both RegA and RegD within an operating hour (Section 3.2.9)
Changes language to conform with M12: Regulation resources must return to their regulation range within 10 minutes of the end of a synchronized reserve event (Section 4.2.12). The current language calls for a return within two minutes.
Clarify hydropower units’ opportunity cost when providing synchronized reserve:
Hydro units providing Tier 2 synchronized reserve receive lost opportunity cost payments only when they are held to condense mode rather than off-line. (Section 4.2.7)
Corrects and clarifies Attachment C regarding cost offers and station manning:
Removes language stating that a resource can submit only five cost offers for energy. The actual limit is “in the 60s,” said Rus Ogborn, of PJM.
Clarifies the compensation rules that apply when PJM requests resources to be manned in order to start units more quickly. Units required to provide staffing will be compensated even if the resource is not called on because system conditions change.
Clarifies and cleans up revisions for Shortage Pricing rules. Changes were made to clarify existing rules and remove errors in the current text.
Two-thirds of PJM’s transmission owners have failed to file FERC-approved tariffs disclosing the methodology they use to calculate customer rates, PJM industrial customers told the Markets and Reliability Committee Thursday.
“There’s a vacuum in the tariff,” said Robert Weishaar, an attorney with McNees Wallace & Nurick LLC who represents several industrial energy users. “There’s a lack of transparency and a lack of accountability… Utilities sometimes change methodologies without notice.”
Weishaar will ask MRC June 27 to approve a problem statement that could result in requirements that transmission owners make tariff filings disclosing their calculation of total hourly energy obligations, peak load contributions, and network service peak loads. The calculations are used to allocate energy, capacity, and transmission cost responsibility among load serving entities.
Weishaar said the disclosures are required by the Federal Energy Regulatory Commission’s “rule of reason” as provisions that affect rates, terms, and conditions.
Weishaar’s proposal is intended to require Baltimore Gas & Electric, PECO Energy, PPL Electric Utilities, Dominion, Dayton, PEPCO, AEP, Duquesne Light Company, Rockland Electric, and Duke to file Attachments M-1 or M-2 to the PJM OATT disclosing their methodologies.
Weishaar said FirstEnergy, Commonwealth Edison, Public Service Electric & Gas, Atlantic City Electric and Delmarva Power & Light have already filed such disclosures.
Weishaar said the descriptions need to be detailed enough to allow LSEs to verify the accuracy of the calculations. Attachments “that merely reference methodologies contained in manuals posted on the transmission owner’s website do not adequately address the problem,” the problem statement says. “Because the necessary level of detail is not included in a FERC tariff, transmission owners may change methodologies, or inconsistently apply methodologies, with little recourse to LSEs and their customers.”
The problem statement also calls for PJM to establish default methodologies that would apply for zones without tariff attachments. It seeks a FERC filing within three months after assignment by the MRC.
The Markets and Reliability Committee gave final approvals to the following manual revisions at their meeting this past Thursday.
Electronic Notifications for Curtailment Service Providers: Changes to Manuals 1 and 18 will implement an automated process that will allow Curtailment Service Providers to provide operational data to — and receive dispatch instructions from — PJM. The new Load Response System (eLRS) process replaces the current manual methods, which rely on email and spreadsheets.
Residual Zone Pricing: Residual Zone Pricing will replace physical zone LMPs for real-time load effective June 1, 2015. A Residual Zone is an aggregate of all load buses in the physical zone, excluding load priced at nodal locations. The change was endorsed by the Members Committee in February 2012 and approved by FERC in Docket ER13-347.
East Kentucky Power Cooperative: PJM needs to add the East Kentucky Power Cooperative zone into PJM markets manuals to accommodate the coop’s integration into PJM, effective June 1.
NERC Reliability Standards: PJM needs to amend M-36: System Restoration to reflect NERC Standards EOP-005-2 (System Restoration Plans) and EOP-006-2 (Reliability Coordination – System Restoration). Updates for consistency with other RTOs; updates underfrequency load shed tables; incorporates recommendations from RFC/SERC audit, and adds specific references to transmission operator restoration plans.
Manual 03A: Energy Management System (EMS) Model Updates and Quality Assurance: The changes include numerous edits for updates and clarity.
Regulation Market Cost-Based Offers: New rules implemented in October require regulation offers to include capability (cost, in $/MWh to reserve a resource for regulation) and performance (costs of tracking the regulation signal in miles/MW). Previous rules, as defined in Manual 15, did not include performance costs.
Manual 35: Definitions and Acronyms: Adds language to Economic Maximum and Economic Minimum definitions; changed Operations Analysis Working Group to Operations Assessment Working Group; Replaced TTV4TF (TO/TOP Version 4 Task Force) with TTMS (TO/TOP Matrix Subcommittee).
NERC standard PRC-023-2: Updates to Manual 14B: PJM Region Transmission Planning Process are required to implement standard PRC-023-2 (Transmission Relay Loadability). PJM annually develops a transmission facility list to comply with NERC criteria.
Manual 03: Transmission Operations: Semi-annual update to incorporate procedural changes.
With its market-leading status in demand response, blue chip clients and international expansion plans, EnerNOC Inc. may be a good long-term investment play on the Smart Grid. But as the last week demonstrated, it’s not for the faint of heart.
EnerNOC’s stock is down 25% — a loss of nearly $134 million in market capitalization — since PJM announced the results of its 2016/17 capacity market auction May 24. The auction saw a 56% drop in RTO-wide capacity prices and a 16% drop in the volume of DR clearing as new natural gas-fired plants and imports increased their market shares.
Stocks of PJM-based utilities also have fallen since the auction, with Exelon Corp. and FirstEnergy Corp. each down 9%.
The auction also may scramble New Jersey’s efforts to subsidize new capacity after a 660-MW natural gas generator planned by NRG Energy failed to clear the auction for the second time despite the state incentives.
No one felt the impact of the auction results more than EnerNOC. Demand response was responsible for 88% of the company’s $278 million in 2012 revenues, with PJM representing 40% of sales for the year (see PJM, FERC Rules Buffet EnerNOC).
Analyst Reaction
EnerNOC’s stock dropped Tuesday after Credit Suisse, one of the underwriters of its 2007 initial public offering, downgraded it from outperform to neutral. Needham & Company cut its price target on EnerNOC shares to $18 two days later while maintaining its buy rating.
Raymond James saw it differently, upgrading the company Wednesday from an outperform rating to a strong-buy rating with a $20.00 price target. And Pacific Crest, which had raised its price target from $22 to $24 on May 8, reversed course Wednesday, dropping the company’s rating from outperform to sector perform.
Motley Fool columnist Travis Hoium wrote Tuesday that the market had overreacted. “Is the company really worth nearly $100 million less today than it was yesterday? Not to a long-term investor, so I don’t think today’s move changes the investment thesis, and if you’re bullish (which I’m not) this should be viewed as a discount more than a reason to panic today.”
EnerNOC did not respond to a request for comment yesterday.
In a press release last week, the company said it cleared 4,400 MW of capacity, a small drop from the 2015/2016 auction, and increased its DR market share in PJM to more than 35%.
“Although we are obviously disappointed with the clearing prices in this auction, it is important to put Friday’s outcome into a broader perspective,” Chairman and CEO Tim Healy said in the statement. “Our results are reflective of our ongoing strategy to strike the right balance between growth and profitability and to not simply be a price-taker where we would be managing demand response resources at a loss.”
The company said it will continue its efforts to increase its revenues from non-DR products and from regions outside PJM.
History
Founded in 2001, EnerNOC has grown by focusing on seven categories of commercial and industrial customers: technology, education, food sales and storage, government, healthcare, manufacturing/industrial and commercial real estate. Its customers include AT&T, General Electric, Pfizer, Sears, Shop Rite and Whole Foods Markets.
The company went public in 2007, with shares ending its first trading day at $31. Those who bought at that price had lost about half of their investment through yesterday. The company has had only one year of profitability (2010) as it has acquired five companies and expanded to Australia, New Zealand and the United Kingdom.
Competition
The company said in its 2012 10-K that it was seeing “increasingly aggressive pricing” on DR from its competitors, and that it might be forced to increase the amount it pays to C&I customers to participate.
Those competitors include privately held Comverge, Inc., whose revenues are about half that of EnerNOC, and Energy Curtailment Specialists. ECS, which operates only in North America, has about 2,000 MW of DR under contract, less than a quarter of that claimed by EnerNOC.
The company also cites competition from natural gas peaking plants, which have benefited from the increased supplies and low price of shale gas.
Nearing the Import Limit
PJM said increases in new gas-fired generation and imports were the biggest contributors to the drop in capacity prices. Most of the nearly 90% increase in imports clearing came from west of PJM.
At the Markets and Reliability Committee meeting Thursday, Andy Ott, PJM’s senior vice president for markets, said the almost 7,500 MW of capacity that cleared from outside the RTO “is pretty close to the limit” on PJM’s import capability.
Ott said almost two-thirds of the imports has firm transmission into PJM and another 20% has firm transmission on part of its path. “It [imports] does have some risk, but we don’t view it as a large risk,” Ott said.
Impact on Utility Stocks
Transmission constraints caused prices to separate within the RTO: Prices in the MAAC region cleared at $119/MW-day, double the RTO’s $59, while the Public Service zone in New Jersey cleared at $219, more than three times as high.
There also was a separation in the response to utility stocks following the auction.
Prices dropped 68% in ATSI, home to FirstEnergy in northern Ohio and PennPower in western Pennsylvania. FirstEnergy’s stock is down 9% through yesterday.
Prices in MAAC dropped 29% and utilities in the region (Pepco Holdings, including Atlantic City Electric and Delmarva Power; Exelon’s PECO and Baltimore Gas and Electric, PPL, ConEdison’s Rockland Electric Co.) fell from 3% to 9%.
New Jersey Impact
Prices in the Public Service region increased 31% while PSE&G’s stock dropped 3%.
New Jersey has agreed to provide almost $3 billion in subsidies to three proposed natural gas plants in the state, but one of them, NRG Energy’s proposed plant in Old Bridge, N.J. failed to clear the capacity auction for the second year in a row.
NRG spokesman David Gaier declined to say yesterday whether the company would proceed with the project. “We’re gong to look at our options over the next several weeks,” he said.
PJM will seek stakeholder approval this month for contingency plans to respond to an Internet outage that forces the RTO to suspend the day-ahead market.
PJM has no procedures for dealing with an Internet outage that could prevent the RTO from receiving participant data needed to solve the day-ahead market. Under the proposed tariff changes outlined to the Markets and Reliability Committee Thursday, all market settlements would be done in real time.
The procedure requires changes to sections 1.10.8 and 1.10.9 of the Open Access Transmission Tariff, including clarification that the rebid period will be from 4 p.m. to 6 p.m. but may be revised by PJM if the clearing of the day-ahead energy market is significantly delayed.
Below is a summary of problem statements and manual, Operating Agreement and Tariff changes approved by the Markets and Reliability Committee Thursday, May 30, 2013.
PMU Deployment
The committee endorsed manual revisions requiring new generators to pay for the installation of phasor measurement units (PMUs). There were four no votes and three abstentions. The Planning Committee approved the changes March 7, rejecting an alternate proposal to have PJM cover the cost.
Reason for change: PMU data can enhance grid reliability for both real-time operations and planning applications (e.g., generation dynamic model calibration and validation, primary frequency response, oscillation monitoring and detection). PJM expects to receive PMU data from 82 substations by the end of 2013 but has none located at generation stations.
Impact: The Interconnection Service Agreement will be changed to require installation of PMUs at new interconnections for generators with nameplate ratings of 100MVA or larger. Data collected by the PMU must be transmitted to PJM continuously and stored locally for 30 days.
Commodity Futures Trading Commission Exemption Order
MRC and the Members Committee approved changes to the Operating Agreement and Tariff to comply with conditions in the Commodity Futures Trading Commission order exempting most PJM market participants from CFTC jurisdiction.
Reason for Change: The CFTC agreed March 28 to largely exempt from its regulations Financial Transmission Rights, day ahead and real time energy transactions, forward capacity transactions and reserve regulation transactions, sales that are already regulated by the Federal Energy Regulatory Commission.
However, the CFTC said the exemption did not apply to financial market participants that cannot qualify as “appropriate persons” under the Commodity Exchange Act (CEA). PJM responded April 7 by announcing it may deny trading privileges to small market participants if they are unable to qualify for the exemption.
Impact: The changes approved Thursday expand financial marketers’ officer certification requirements. Although the changes require FERC approval, PJM CFO Suzanne Daugherty said her staff will immediately begin contacting about 100 market participants for whom the RTO does not have sufficient financial information.
The MRC was asked to choose between two options regarding the financial qualifications of an unlimited guarantor.
Stephanie Staska, of Twin Cities Power LLC, proposed language requiring “an issuer that has at least $1 million of total net worth or $5 million of total assets per Participant for which the issuer has issued an unlimited Corporate Guaranty.”
PJM proposed that the guarantor be “an issuer that would qualify for an Unsecured Credit Allowance of at least $1 million.”
Daugherty said the Twin Cities language complied with the CFTC order but was “just a little less thorough” than PJM’s proposal.
Staska said her proposal was identical to that used by MISO for compliance with FERC order 741. “It “does just as much to protect the market,” she said.
The changes were approved with the Twin Cities language with no objections and three abstentions.
MRC and the Members Committee endorsed credit requirements for up-to-congestion (UTC) trades, a fast-growing virtual transaction that previously had no credit requirements.
Reason for Change: UTC trading volumes have grown dramatically since 2010 but there are no credit requirements to protect market participants against defaults.
Impact: Bid screen and cleared portfolio credit requirements are based on a percentile of the difference between each member’s bid or cleared price and the two-month rolling average of real-time value per path.
Traders who fail the credit screen based on their initial bids will be able to rebid within their limits.
MRC approved a manual change documenting the Market Monitor’s current application of the FTR forfeiture rule on increment and decrement transactions and a problem statement to determine how the rule should be interpreted in the future.
Reason for Change: PJM discovered only recently that it disagreed with the criteria by which the monitor has been determining whether a company’s virtual bid is “at or near” the delivery or receipt buses of its FTR.
Impact: The manual change documents the monitor’s interpretation of the rule. The inquiry may result in changes to the application of the rule.
The monitor has been applying the penalty based on the net impact of virtual bids, triggering its application in less than one-tenth of 1% of trades. PJM proposed a different calculation under which companies would lose any profit for an FTR if 75% or more of the energy injected or withdrawn by a virtual bid is reflected in a constrained path between FTR source and sink.
“We believe this is about as clear as we can make it,” Stu Bresler, PJM vice president of market operations, said of the manual change.
The problem statement was approved over the objections of 15 members of the PJM Public Power Coalition.
“There are at least five new problem statements on this week’s agenda,” said Bill Schofield, of Customized Energy Solutions, which represents the coalition. “This is not the time to be adding this to our plate.”
But representatives of financial marketers said revising the rule was important to them.
“Because of the heightened risk in terms of FERC enforcement action … I think it’s important that we get some clarity on how we analyze these power flows,” said Greg Pakela of DTE Energy Trading. “This kind of acts as a safe harbor.”
FTRs are “a fundamental building block to the forward price curve,” said Bruce Bleiweis, of DC Energy, LLC. “Many people would like some additional clarity here.”
Market Monitor Joseph Bowring also supported the review, noting that the rule has been unchanged since 2001. “Are we getting false positives or false negatives?” he asked. “We need to make sure everyone understands the rule. I think there’s a lot of misunderstanding.”
MRC approved a problem statement creating a senior task force to take a broad review of its method of providing Operating Reserve payments.
Reason for Change: PJM said changes are needed to reduce growing uplift costs. Operating Reserves are “make whole” payments that ensure generators dispatched out of merit for system reliability don’t operate at a loss. Because they are collected through uplift charges and not reflected in day-ahead or real-time locational marginal prices, they cannot be hedged.
Impact: The task force will consider revising the sources of Operating Reserve charges and the methodology used to allocate them. The goal will be to minimize uplift costs while ensuring market prices are consistent with operational reliability, decrease charge rates, and reduce transaction risk due to variable fees.
Alternative 1 removed from the calculations only the five-minute periods in which a curtailment occurred rather than the full hour, as in current practice.
