PJM’s promotion of Andy Ott to replace retiring CEO Terry Boston has prompted a series of additional organizational changes and promotions effective July 8.
From left to right: Mike Bryson, Stu Bresler, Nora Swimm and Thomas O’Brien.
Ott, formerly executive vice president of markets, becomes CEO-elect.
Mike Kormos, formerly executive vice president of operations, was promoted to executive vice president and COO. His deputy, Mike Bryson, formerly executive director of system operations, will become vice president of operations.
Ott’s deputy Stu Bresler, formerly vice president of market operations, becomes senior vice president of market services.
“It was Andy’s chance to put his [stamp] on the organization,” Boston said of the changes in an interview on Monday at the Mid-Atlantic Conference of Regulatory Utilities Commissioners in Williamsburg, Va.
Boston said the changes were largely prompted by the desire “to get Stu Bresler in place to run the markets” as Ott takes on more travel. “I told [Ott], ‘You think you do a lot of traveling now, you haven’t seen anything yet.’”
PJM’s settlements unit, formerly overseen by Bresler, is moving to the RTO’s financial group to ensure more independence.
Bryson’s responsibilities will increase as Kormos takes on a new direct report in Denise Foster, vice president of state and member services, who formerly reported to Ott.
In addition, Nora Swimm was promoted to senior vice president of corporate client services, from vice president of human resources and corporate client services, and Thomas O’Brien was named vice president and chief information officer, from vice president of information and technology services.
Boston said Swimm is taking on responsibilities for physical security while O’Brien’s new title was to recognize the expansion of his role in recent years, in which he has served as CIO without the name and PJM has begun dealing with cyber threats.
VALLEY FORGE, PA. — The electric industry’s historic shift to natural gas will aid its compliance with federal regulators’ pending carbon emission rules and provide a boon for gas producers. But the shift won’t be accomplished, speakers said at the PJM Grid 20/20 symposium last week, without an answer to a difficult question: Who will bear the cost of building new pipelines to relieve constraints, and how will they be incented to take on the expense?
Outgoing PJM CEO Terry Boston expressed confidence in the future, saying, “This is the first time in my career I can say that energy independence for the United States of America is attainable.”
The gas and electric industries, he said “are connected at the hip.” There’s not a lot of room for error, he said, “between just-in-time and too-dang-late.” ISO-NE CEO Gordon van Welie who keynoted the conference, shared the challenges faced by New England, where natural gas’ share of electric production has ballooned from 15% in 2000 to 44% in 2014. The region adopted a Winter Reliability Program and Pay-for-Performance incentives to encourage upgrades and improvements to fuel reliability.
“Natural gas infrastructure has not kept pace with the tremendous growth in gas-fired generation,” van Welie said. “We don’t think response to Pay-for-Performance alone is going to result in investments in natural gas pipelines.”
Meanwhile, he said, “It’s not that our situation is getting better — it is getting worse.”
Speakers said the Federal Energy Regulatory Commission’s April order moving the timely nomination cycle deadline for scheduling gas transportation to 1 p.m. CT from 11:30 a.m. CT and adding a third intraday nomination cycle should improve coordination between the two industries. (See FERC Approves Final Rule on Gas-Electric Coordination.)
“The idea of adding more cycles, it can’t hurt,” said Joseph Kienle, director of Dominion Transmission. But, he said, “At the end of the day, if I’m in a winter situation and I’m fully subscribed, it doesn’t matter how many cycles you add.”
Andy Ott, who will become PJM’s CEO upon Boston’s retirement, said operational awareness of the natural gas industry has expanded from being a winter concern. PJM in May reconvened its gas “war room” to stay abreast of issues. “This is going to become a normal course of business,” he said. “It’s becoming an annual, year-round phenomenon for us.”
Outgoing FERC Commissioner Philip Moeller encouraged attendees to be proactive in recommending solutions to the commission and its new chairman Norman Bay. “He’s got a bigger, steeper learning curve to tackle,” he said. “Keep that in mind because he’s the person who will lead the commission at least for the next one and a half years.”
Moeller said he has been impressed so far with Bay, who he said is trying to bring the commissioners into decision-making conversations earlier. He declined to comment on Bay’s lone dissent on PJM’s Capacity Performance proposal, citing a “99.99% chance of rehearing that order.”
“My main message to you is: Creative ideas are welcome. We need desperately to keep the momentum going on this issue,” he said.
FERC is good at dealing with singular issues, he said, but, “Sometimes being able to see out a little farther is a challenge the commission has.”
MILWAUKEE — MISO Independent Market Monitor David Patton on Wednesday called for tighter rules on wayward generators, more precise real-time pricing and a fix for Financial Transmission Rights funding shortfalls. He also engaged in a spirited debate with board members over his longstanding complaints about the RTO’s voluntary capacity market.
Patton outlined the proposals, contained in the Monitor’s 2014 State of the Market Report, during a presentation at the Markets Committee of the Board of Directors at MISO’s Annual Meeting in Milwaukee.
Board members’ repeated interjections ate up the clock and forced Patton to defer further discussion about some recommendations to a future Markets Committee meeting.
Five-Minute Pricing
One of Patton’s “high-priority” recommendations is to implement five-minute settlements for generators in the real-time market, something he raised three years ago.
“This is one area where we’re not leading, and it has real consequences,” Patton said after rattling off a list of positive metrics for MISO during 2014.
MISO dispatches the real-time market in five-minute intervals but settles based on hourly average prices. Patton said the inconsistency reduces the incentive for generators to follow dispatch signals and results in increased uplift.
“The response to our dispatch signal by a lot of our suppliers is pretty ragged and it affects us from a reliability standpoint and it affects us from an economic standpoint.”
Patton noted that SPP and NYISO both use five-minute settlements. MISO won’t be able to do so until it installs a new settlement system.
Todd Ramey, vice president of system operations and market services, said the system is expected to be installed next year, but it would be 2017 before members’ systems would be ready to accommodate the shorter pricing intervals. “The question mark is ultimately whether the membership says ‘please proceed with five-minute settlements.’”
He said the $28.6 million in increased generator revenue that the Monitor estimates would result from the change is “way less” than 1% of their overall revenues.
“From the market participant perspective, they’re trying to weigh … the changes they would need to make to accommodate five-minute settlements versus the additional revenue,” Ramey said.
Patton replied that a better comparison is the impact after accounting for fuel costs. “If you compare it against net revenue, it’s actually way more significant,” he said.
FTR Funding
Patton also offered a new recommendation for the longstanding problem of underfunding FTRs.
Shortfalls, but none of the surpluses, are allocated to FTR holders. MISO funded 96% of FTRs in 2014.
“We’ve created a financial instrument and created an unnecessary uncertainty about what that instrument is actually worth,” Patton said. “It lowers the prices of our FTRs, so we collect less revenue when we sell the FTRs, which hurts our transmission customers.”
Patton said shortfalls caused by transmission outages or derating should be allocated to those responsible for the diminished transmission capacity, as is done in NYISO. The current approach has provided incentives for some “relatively unseemly outages,” including some during the polar vortex last year that generated hundreds of millions of dollars in congestion, Patton said.
“You would wonder why [outages] were being scheduled at that time of the year in the northern part of our system.”
30-Minute Local Reserve Product
The Monitor also recommends that MISO introduce a 30-minute local reserve product, saying the RTO incurs high uplift costs in some areas to satisfy voltage and local reliability requirements beyond first contingencies.
The reliability requirements would be best addressed by quick-start gas turbines, which are in very short supply in MISO South, Patton said. As a result, slower-responding units are paid to be online even though they’re not economic.
Patton said the new product would provide incentive to invest in quick-start units. “When [the cost is] embedded in uplift, you’re not providing an investment signal,” he said.
Tighten Thresholds
Another recommendation, first made by the Monitor in 2012, is to tighten thresholds for uninstructed deviations by generators. Patton said MISO is “substantially more lenient” than other RTOs in setting the bandwidth for measuring compliance, using a tolerance band of 8% and four consecutive intervals.
Patton said generators not following dispatch are nonetheless receiving a “significant amount” of ancillary services and price volatility make-whole payments.
In addition, he said, the RTO is losing as much as 400 MW due to derates during peak conditions, “a meaningful portion of the headroom that we have to operate the system. This has some reliability implications and it has economic implications.
“We think it’s very important and there’s almost nothing that’s been accomplished in terms of moving this forward,” he said. He said referrals to the Federal Energy Regulatory Commission’s Office of Enforcement have improved performance somewhat.
Interface Pricing
Patton repeated his call for removing external congestion from interface prices, saying the current rules are resulting in inefficient imports and exports. Patton has previously called for a FERC technical conference to resolve MISO’s differences with its neighboring RTOs. (See Patton Asks FERC to Set Deadline on PJM-MISO Interface Pricing Dispute.)
“We’re seeing virtually no progress toward any consensus solution” with PJM, he said. “SPP is a little closer to understanding the issue than PJM.”
“We think it’s extremely important that MISO move forward unilaterally,” he added later.
Capacity Market
Patton drew pushback from some board members when he displayed a slide showing that generators’ net revenue in MISO is far below the estimated annual cost of a new combustion turbine or combined-cycle plant.
Left to right: Todd Ramey and Richard Doying, MISO; David Patton, Potomac Economics
“We’re not very close to motivating anybody to build anything in MISO,” he said. “For RTOs with functioning capacity markets, they would be meeting or exceeding the cost of new entry.”
Patton said that could be fixed by making several changes to the Planning Resource Auction for capacity, including adding seasonal capacity requirements and replacing the vertical demand curve with a sloped curve similar to that used in PJM.
Committee Chairman Michael Curran was unconvinced by Patton’s analysis. “As I’m struck by this chart, I’m thinking we still manage to get things built.
“One’s led to believe if you’re vertically integrated you have a monopolistic power, therefore you’re going to be able to exploit the poor state regulators and get really high prices … but in our market, MISO came through as the lowest cost market,” he said, citing an analysis from the ISO/RTO Council.
Patton responded that MISO has a “tremendous cost advantage” because of low-cost fuel.
“All of our [independent power producers] want to get out of MISO and … that causes our vertically integrated utilities to have to build resources that are more expensive than maintaining the existing resources that we have. And it also puts all that investment risk on the backs of regulated ratepayers instead of investors.
“MISO has been enjoying a capacity surplus for a long time,” he added. “When states have to build new generation … that’s when you’re going to see the costs appear.”
Board Chairman Judy Walsh also waded into the debate, saying Patton needed to provide more data regarding other regions’ costs. “This chart doesn’t do it,” she said.
Director Paul Feldman said the board had authorized Patton to share his proposed changes with state officials, who have been opposed to anything resembling PJM’s mandatory capacity market. “So you didn’t do a good [sales] job,” he said, prompting laughter.
Director Paul Bonavia was a bit more conciliatory. He said if Patton could convince the stakeholders that MISO could have a more robust capacity market without increasing overall costs, “that would change the dialog a lot.”
At the end of the meeting Curran thanked Patton for his independent analysis but couldn’t resist a little jab.
“You’re going to have a sloped demand curve on your tombstone.”
“Cause somebody’s going to kill me?” Patton responded, laughing nervously.
“No,” Curran said. “This is the Midwest. These are nice people.”
MILWAUKEE — Dynegy CEO Robert Flexon last week defended his company’s bidding strategy in MISO’s April capacity auction and said the controversy over the results signals the need for a regulatory change in Illinois.
On May 28, Public Citizen Inc. and the Illinois Attorney General asked the Federal Energy Regulatory Commission to investigate whether Dynegy illegally manipulated MISO’s Planning Resource Auction, resulting in a nine-fold price increase in Zone 4. Public Citizen also alleged that MISO rejected recommendations by its staff that Zones 4 and 5 be merged due to their concerns about Dynegy’s growing share of capacity in Zone 4 after the company acquired four generators in the zone from Ameren. (See Public Citizen: Investigate Dynegy Role in MISO Auction.)
Zone 4, comprising much of Illinois, cleared at $150/MW-day, compared with just $16.75 a year earlier. Clearing prices in the rest of MISO were less than $3.50/MW-day.
In an interview before his appearance in a panel discussion at the MISO Annual Meeting last week, Flexon said that the company had properly offered all of its generating units into the auction based on their operating costs. “Nothing was withheld,” he said.
Flexon said the auction results pointed to the disconnect between Illinois, which has retail choice, and the other14 states in MISO, which operate under cost-of-service rate regulation. Southern and Central Illinois are in MISO, while the Chicago area is part of PJM, where most states have retail choice.
“If you do the math, we’re getting about $50/MW-day where all of the [utilities in the] regulated states are getting about $300 to $350 per MW-day via rates,” he said — the $50 an average including units that did not clear.
“You have a market where it’s designed where all of the other 14 states will take all of their capacity and [price] them at zero … and then people compare our [prices] to theirs and they’re actually getting 10 times what we’re getting. But we’re getting all the [criticism] because we only have two ways of compensation.”
Flexon said the company bid its units in at “basically a marginal cost.”
“We look at each unit and we look at the economics and the cash flow and we bid it in at the cost. We balance the energy market with the capacity market. So some units are cheaper to run than others. So we had some units that cleared and some units that don’t. … It does us no good to offer it in at $3/MW-day like the [regulated utilities do].”
Move to PJM?
Flexon reiterated his desire to move his generation into PJM. He said the company is trying to convince Illinois officials to support a change in their regulatory construct.
“The message I’ve really got to take to Illinois is that Central and Southern Illinois — being a part of MISO in the deregulated state — there’s no future for [merchant] generation in Central and Southern Illinois if you don’t change the construct. We’re going to continue to get every megawatt we can into a market that’s designed with like competitors.
“I think Illinois needs to look at that and say this construct doesn’t work. And that’s why [Exelon’s] Clinton [nuclear] plant can’t survive.
“Whether you do that within the parameters of MISO; whether we make Zone 4 designed a little different; whether you reregulate or whether you try … to push the whole state into PJM — I don’t know what the answer [is] there. Those are possible solutions.”
MISO Response
In a question-and-answer session with MISO’s Board of Directors afterward, Chairman Judy Walsh thanked Flexon for his candor. “I don’t think this is a problem that we didn’t know about,” she said.
Brett Kruse of Calpine said the aberrant prices weren’t in Zone 4 but in MISO’s other regions, where prices were much lower. “It is not the correct price signal. I think most economists would probably agree with that. So given all the challenges MISO’s had over the years … maybe it’s time for MISO and the board to say, ‘Maybe there’s another way to do it,’” he said.
MISO CEO John Bear said the RTO has been talking with Illinois officials about developing “a separate mechanism for that state — which I think is a way for us to address that problem without having to do anything different across our vertically integrated states, who are quite happy with the resource requirements that we have now.”
“I think that’s something that we ought to try to get some traction on … pretty quickly,” Bear added.
The Federal Energy Regulatory Commission again rejected Consolidated Edison of New York’s request that it force PJM to recalculate the cost allocation for two transmission upgrades in northern New Jersey, raising questions about whether the company will seek alternatives to the so-called “PSEG wheel” for delivering power to New York City.
PSEG short circuit solution (Source: PJM Interconnection LLC)
The commission last week rejected Con Ed’s November 2014 challenge (EL15-18) and a rehearing request by Con Ed, the New York Public Service Commission and Linden VFT on an earlier order in the dispute (ER14-972).
PJM assigned Con Ed $629 million of the costs of a $1.2 billion transmission upgrade to address a short-circuit problem in the Public Service Electric and Gas transmission zone outside New York City. PSE&G was allocated $52 million of the cost.
Con Ed was also assigned $51 million of PSE&G’s $100 million Sewaren storm-hardening project. The company says it should be assigned only $29 million for the two New Jersey projects.
PJM said Con Ed’s responsibility resulted from its use of the “Con Ed-PSEG wheel,” in which Public Service Enterprise Group, PSE&G’s parent company, takes 1,000 MW from Con Ed at the New York border and delivers it to Con Ed load in New York City.
In April 2014, FERC rejected Con Ed’s attempt to avoid paying for the short-circuit project but said it wanted more information on how PJM performed the distribution factor (FERC Rejects Con Ed Challenge on Tx Upgrade.) In last week’s order, the commission accepted PJM’s compliance filing, saying it was satisfied that the RTO had conducted the DFAX analysis correctly.
In filing the second complaint, Con Ed had sought a broader consideration of the cost allocation than the rate filing that prompted FERC’s earlier order.
‘Objectively Unreasonable’
Con Ed said PJM’s Tariff requires a review of instances where its cost allocations will produce “objectively unreasonable” results. The commission, however, sided with PJM, saying that “that the provision limits the discretion in reviewing the results of the solution-based DFAX method analysis to its engineering judgment of the flows over the subject facility.”
It agreed with PJM that, based on its Tariff and Order 1000, the RTO can use a “substitute proxy” only “when the solution-based DFAX method analysis cannot be performed for the facility in question and the resulting flows are not consistent with the normal expected flow results that an engineer would expect to see.”
FERC said PJM was able to properly conduct the analysis.
“Because Con Edison has provided no evidence the flows were not properly measured, there was no basis upon which to disregard those results,” the commission said, adding that the Tariff did not permit PJM the discretion to use a substitute proxy based on whether the resulting cost allocation appears unreasonable.
“Such an interpretation would require PJM to ignore the cost allocation procedures of its Tariff and examine every cost allocation to determine whether it is objectively unreasonable. We also find that such an interpretation would provide PJM with too much discretion and is at odds with the requirement in Order No. 1000 for determining ex ante cost allocation procedures, so all parties will know in advance how project costs will be allocated.”
Con Ed also protested the way PJM nets transmission usage, saying it discriminates against point-to-point customers and makes incorrect assumptions about the source of the generation serving its New York load.
PJM nets a customer’s positive energy flows with its negative flows, modeling the transmission zone as a whole and not bus-by-bus. PJM said that wouldn’t apply to Con Ed because its energy flows in only one direction over the Bergen-Linden Corridor.
Planning Transparency
FERC also rejected the complaints of Con Ed and Linden — which owns a 315-MW merchant transmission facility that interconnects both PJM and NYISO — about the transparency of PJM’s transmission planning process. FERC repeated its observation from the April 2014 order that the RTO had discussed the project during numerous Transmission Expansion Advisory Committee meetings in 2013. “Con Edison could have, but did not [raise] cost allocation issues at the TEAC meetings,” FERC said.
Con Ed’s contract for the wheel expires April 30, 2017, unless the company chooses to roll over the service. Con Ed spokesman Mike Clendenin said the company has not decided on whether it will appeal the ruling or renew the contract for the wheel.
“We are concerned about the unfair costs to our customers and will be reviewing our options,” he said.
“We’ve got some time,” he added, noting that the company would have to give notice of its intention regarding the contract in 2016.
Con Ed’s peak load in New York’s five boroughs and Westchester County is more than 13,000 MW.
PJM acted properly in its solicitation of bids to fix a stability issue at the Artificial Island nuclear complex, the Federal Energy Regulatory Commission has ruled, denying a request by losing bidder Public Service Electric and Gas seeking to have the project reposted.
While the commission found that PJM was not required to use its Order 1000 solicitation rules because the call for bids predated that measure, Commissioner Cheryl LaFleur said the case presented an opportunity to consider the order’s competitive solicitation procedures more generally.
“One of Order No. 1000’s key goals was to harness the benefits of competition in transmission development for customers, and it is important that, as regions implement their Order No. 1000 procedures, we do not lose sight of that goal: facilitating the identification, development and ultimately the construction of more efficient or cost-effective transmission projects that are better for customers,” she wrote in a separate note included with the ruling (EL 15-40).
PSE&G had accused PJM of failing to follow its own rules by unilaterally modifying finalists’ proposals and allowing LS Power – the winning bidder – to modify its proposal more than a year after the proposal window closed. (See PSE&G: PJM Broke the Rules in Artificial Island Solicitation.)
If PJM did not believe that any one proposal represented the most efficient or cost-effective solution, PSE&G said, it should be required to repost the solicitation.
PJM countered that such an interpretation of the rules “would result in PJM engaging in interminable, never-ending solicitations until the perfect project was proposed, with the inevitable result that PJM would have to default to assigning many projects to incumbents due to time constraints.” (See PJM: PSE&G’s Remedy for Artificial Island Bid Process ‘Draconian,’ ‘Self-Serving.’)
In addition, it said, that type of thinking “would turn the Order No. 1000 solicitation process into a strict bidding process of the type that would govern homogenous products such as the purchase of paper clips.”
PJM also noted that without the authority to combine and modify proposals, “it would be left with accepting a proposal four times as expensive as the combination it is considering.”
FERC concluded, “PJM followed its commitment to evaluate Artificial Island proposals using its then-effective transmission planning process and to incorporate its new Order No. 1000 proposal window into that process ‘to the extent feasible and practicable.’”
PJM planners announced April 28 that they would recommend to the Board of Managers that LS Power build a new 230-kV transmission line from New Jersey’s Artificial Island to Delaware at a cost of $146 million. (See PJM Staff Picks LS Power for Artificial Island Stability Fix; Dominion Loses Out.) PSE&G and Transource Energy were chosen for necessary connection facilities.
PSE&G initially was picked for the job last summer, but the Board of Managers reopened the bidding following an outcry from losing bidders, New Jersey officials and environmentalists.
The Board of Managers once again will be asked to decide the issue at their meeting July 29. Prior to that, PJM planners will present their recommendation to the board’s four-member Reliability Committee.
With just seven weeks until PJM conducts its first Base Residual Auction incorporating the newly approved Capacity Performance product, stakeholders gathered last week for a peek at the comprehensive changes Manual 18 must undergo before resources begin submitting offers.
But there were more questions than clarity at the specially called Markets and Reliability Committee meeting. It was scheduled for three hours but went on for more than six, as tempers ran high and patience low.
“I’m frustrated and I’m crying,” said Old Dominion Electric Cooperative’s Ed Tatum during a discussion of unit-specific parameters. “This is really complicated.”
At issue was whether units adhering to their parameters were safe from penalty in an emergency situation. The answer? No.
“It governs what we will pay in uplift cost, and that’s not what we wanted either,” Mike Kormos, senior vice president for operations, told Tatum. “But it will not govern whether you are in a penalty or not. It is not what we filed. It is the order we got.”
Dozens of scenarios were presented: What can be used for replacement capacity? When does the force majeure provision go into effect? What difference does it make if it’s a transition year? How do we know why we weren’t called? What happens if you choose to self-schedule? And most commonly, when and how are non-performance charges assessed?
Stakeholders have one more education session on Wednesday before the red lines to the 235-page manual are presented for endorsement to the MRC the following day. (The Members Committee, which follows the usually short MRC gatherings, has been canceled.) (See FERC OKs PJM Capacity Performance: What You Need to Know.)
PJM staff urged stakeholders to send their questions to capacityperformance@pjm.com to be considered in Wednesday’s training.
PJM must make a compliance filing to the Federal Energy Regulatory Commission by July 9.
“We need to get this manual out there and discussed,” PJM’s Dave Anders said. “We do not have the luxury of time to go through multiple iterations.”
The new Capacity Performance product is a response to poor generator performance during the polar vortex of January 2014. It aims to strengthen grid reliability by rewarding overperforming participants and charging under-performers penalties.
The changes will be phased in over the 2018/19 and 2019/20 delivery years.
The Federal Energy Regulatory Commission last week denied a request by Ameren that its native load in the “Bootheel” region of southeastern Missouri be considered part of MISO’s Ameren Missouri transmission pricing zone rather than the Entergy Arkansas zone.
The commission rejected Ameren’s request for a declaratory order (EL14-46).
FERC said while sections of a 2004 service agreement exempted Ameren Missouri from MISO charges for the bundled retail load, the agreement also requires Ameren to pay for services it does not provide itself, such as the transmission service provided by Entergy Arkansas. The commission said that “a fundamental tenet of contract interpretation is that a contract provision should be interpreted … as consistent with the contract as a whole.”
The Bootheel load refers to Ameren Missouri’s native load customers in the corner of the state south of St. Louis. Until 1991, that load was served by Entergy Arkansas’ predecessor, Arkansas Power & Light. In 1991, APL sold its distribution system serving retail customers in Missouri to Ameren but retained its transmission facilities.
As a result, the Bootheel load is connected to Entergy Arkansas’ transmission facilities in Missouri and has no direct interconnection to the Ameren Missouri grid.
Ameren Missouri, which joined MISO in 2004, served that load until December 2013 with network integration transmission service from Entergy Arkansas. A grandfathered agreement between the two companies was in effect until 2009, when a new agreement was entered.
FERC was not persuaded by Ameren’s argument that denying its petition would take jurisdiction over the transmission component of its bundled retail load from the Missouri Public Service Commission. “The Missouri commission did not have the ability to set the rate for transmission service to the Bootheel load … prior to Entergy Arkansas’ integration into MISO [in 2013], and Entergy Arkansas’ integration into MISO does not change that.”
In a statement, Ameren said, “While Ameren Missouri is disappointed with the Federal Energy Regulatory Commission’s decision, we have decided to accept the decision.”
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:40-10:00)
Members will be asked to endorse the following manual changes:
Manual 19: LoadForecasting and Analysis — Makes change to residential measurement and verification rules approved in November. Provides a solution for the issue that some electric distribution companies (EDCs) are prohibited from sharing personally identifiable information about residential customers participating in demand response programs. EDCs may use unique ID numbers instead.
Manual 03: Transmission Operations — Requires a separation between emergency and load dump ratings. In the event they are the same, the emergency rating submitted by the transmission owner shall be, at a minimum, 3% lower than the load dump rating. If this change results in a normal rating that is higher than the long-term emergency (LTE) rating, the TO shall, at a minimum, make the normal rating equal to the LTE rating.
Manual 3A: Energy Management System Model Updates and Quality Assurance — Continues effort to streamline sections regarding model updates. Most significant change is new section on sub-transmission model submission requirements. Appendix A revised to clarify business rules and tool interaction.
3. CAPACITY PERFORMANCE (10:00-11:30)
Manual 18: PJM Capacity Market — Changes introduce new Capacity Performance products; outline transition; address resource adequacy and demand in the Reliability Pricing Model; describe supply resources in the RPM; explain demand resource requirements and RPM auction credit rates; outline the CP must-offer requirement; address intermittent and capacity storage resource sell offers; describe resource performance assessments, non-performance assessments and expected performance vs. actual performance; outline fixed resource requirement alternative; and review CP transitional Incremental Auctions. Members will be asked to endorse changes so PJM may complete its compliance filing, due July 9 to the Federal Energy Regulatory Commission. (See related story, PJM Stakeholders Rush to Figure out What’s Changing for the BRA.)
