FERC last week denied requests by Texas and Louisiana regulators for rehearing of its December 2013 order approving the Entergy operating companies’ incorporation into MISO and Entergy Arkansas’ exit from the companies’ system agreement.
The Public Utilities Commission of Texas contended FERC was wrong because in filing “limited” amendments to the agreement, Entergy didn’t subject its entire system agreement to scrutiny.
The Louisiana Public Service Commission contended that FERC’s order failed to determine what entity is responsible for costs left when an operating company withdraws. It said ratepayers of the last remaining company in the operating company system could unjustly bear the brunt of the costs needed to plan and operate the resources of multiple companies. Louisiana regulators also questioned whether Entergy’s proposed congestion cost would correspond with MISO practices and suggested that Entergy Arkansas’ exit would leave a regulatory gap in state authority over Entergy.
FERC’s Nov. 9 order denied the commissions’ complaints on all fronts, saying that the system agreement doesn’t require withdrawing companies to pay an exit fee or otherwise compensate remaining companies (ER13-432-001).
“[Entergy Arkansas’] integration into MISO does not require a broader review of the system agreement. Nothing about Entergy’s intent to operate as a power pool within MISO is inherently inconsistent with behavior in an organized market,” FERC wrote. “Furthermore, nothing in the system agreement or commission precedent would bar Entergy from integrating the operating companies into MISO as a power pool.”
FERC last week also accepted Entergy’s compliance filings required by the 2013 order (ER14-1263, et al). The commission had ordered the companies to amend their costs and credits allocator to use energy usage instead of peak demand as the basis for calculations.
The Louisiana commission protested that Entergy’s revised allocator “departs dramatically from the criteria articulated by the commission” by using monthly energy usage data instead of hourly energy usage data, as MISO’s Tariff states. They asked FERC to reject Entergy’s method on the basis that it violated cost-causation principles.
FERC instead accepted Entergy’s compliance filing, noting that using hourly energy usage data “would be problematic because it would be inconsistent with the monthly allocation of ancillary services and uplift charges and credits related to generating units.”
“We find that Entergy has provided sufficient detail in its compliance filing to explain how it will calculate the energy-based allocator and has justified why its proposal is just and reasonable,” the commission wrote.
FERC Commissioner Colette Honorable, a former Arkansas regulator, did not participate in either ruling.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:40)
Members will be asked to endorse the following manual changes:
Manual 01: Control Center and Data Exchange Requirements. Adds requirements and changes terminology to be consistent with North American Electric Reliability Corp. standards. Makes minor edits for clarity. Removes dated reference to “floppy disk.”
Manual 03: Transmission Operations. Changes resulting from bi-annual review include project updates, edits and reorganization of sections.
Manual 12: Balancing Operations. Updates due to new instantaneous reserve check implementation. Eliminates mention of MISO as the Interconnection Time Monitor.
Manual 13: Emergency Operations. Updates day-ahead scheduling reserve requirement for Reliability First Corp. effective Jan. 1. Other changes made for consistency. Removes requirement that generators connected below 230 kV participate in voltage reduction.
Revisions to Manual 19: Load Forecasting and Analysis reflect updates to the PJM load forecast model. Adds variables to account for trends in equipment and appliance saturation and energy efficiency; revises weather variables; updates weather station assignment to zones; and revises weather normalization procedure. PJM will be publishing a white paper in 2016 to provide more detail on the forecast model. (See “Manual Changes on Load Forecast Approved Except for Solar Revision” in PJM Planning Committee and TEAC Briefs.)
Revisions to Manual 18: PJM Capacity Market and Manual 18B: Energy Efficiency Measurement & Verification to accommodate energy efficiency resources in the capacity market when they are reflected in the peak load forecast.
The committee will be asked to endorse modifications, clarifications and revisions to 12 terms in PJM governing documents.
xx. UNDERPERFORMANCE RISK MANAGEMENT IN RPM/CP (10:25-10:40)
Bob O’Connell, on behalf of the Supplier Caucus, will present a proposed problem statement and issue charge related to underperformance risk management in the capacity market. It would expand ways for generators to minimize penalties by netting them against over-performing generators. (See Generators Seek to Reopen PJM Capacity Performance Rules.)
Members Committee
ENDORSEMENTS (1:25-2:05)
1. 2015 IRM STUDY RESULTS (1:25-1:40)
Members will be asked to endorse the installed reserve margin study results, re-setting IRM and the forecast pool requirement for 2016/17, 2017/18 and 2018/19 and establishing initial IRM for 2019/20. The study increases the IRM to 16.4% from 15.5% in the 2014 study. The IRMs also rose for the following two delivery years. (See “Committee Endorses Increase in IRM” in PJM Markets and Reliability & Members Committees Briefs.)
2. 2016/17 THIRD INCREMENTAL AUCTION (1:40-1:55)
As part of the transition to Capacity Performance, the committee will be asked to approve Tariff revisions allowing PJM to sell excess base capacity acquired in the third Incremental Auction for 2016/17 in February. (See “Tariff Change Would Allow PJM to Sell Excess Capacity for 2016/17” in PJM Markets and Reliability & Members Committees Briefs.)
3. ELECTIONS (1:55-2:05)
Members will be asked endorse the following elections:
Finance Committee
End Use Customer, David Evrard, Pennsylvania Office of the Consumer Advocate
Generation Owner, Michelle Greening, Talen Energy
Other Supplier, Marguerite Miller, Credit Suisse
Transmission Owner, Jim Benchek, FirstEnergy
Sector Whips
Electric Distribution, Steve Lieberman, Old Dominion Electric Cooperative
End Use Customer, Susan Bruce, PJM Industrial Customer Coalition
Generation Owner, Joe Kerecman, Calpine
Other Supplier, Katie Guerry, EnerNOC
Transmission Owner, Jodi Moskowitz, Public Service Enterprise Group
WASHINGTON — PJM transmission owners defended their jurisdiction over maintenance of the grid last week under questioning by FERC staff at a technical conference held to gain insight into the RTO’s local planning process.
Commission staff questioned PJM officials for almost four hours on subjects ranging from the difference between its Planning Committee and Transmission Expansion Advisory Committee to what is discussed at its sub-regional committee meetings.
Zeny Magos, FERC asking a question.
The staffers were particularly interested in learning how PJM reclassifies supplemental projects as baseline projects in its Regional Transmission Expansion Plan and how it determines whether local transmission needs should be opened to competitive proposals under Order 1000.
FERC ordered the conference in September, partially in response to a complaint by Dayton Power & Light over the reclassification of the Cunningham-Elmont 500-kV end-of-life project in Virginia as a baseline project in the 2015 RTEP. Dominion Resources originally proposed the rebuild as a supplemental project, meaning it would bear the full costs. (See FERC Sets Tech Conference on PJM Tx Planning Rules.)
In June, FERC issued a deficiency letter seeking additional information on PJM’s cost allocations for 61 baseline upgrades, including the Cunningham project. In its response, PJM acknowledged that “there is no specific language in either [the Tariff] or the PJM manuals that explains how PJM re-categorizes a supplemental project to a required transmission enhancement eligible for regional cost allocation.”
Supplemental Projects
PJM Vice President of Planning Steve Herling, who did most of the talking for PJM at the hearing, told FERC that supplemental projects are proposed at the discretion of the TOs and are not in response to any violations of North American Electric Reliability Corp. standards or the TO’s own planning criteria. They’re often proposed to replace aging infrastructure. “If you went down the list in our database, I guess half of them start with the word ‘replace,’” he said.
Supplementals “could very well mask a violation that would have otherwise arisen, and it will not be obvious to anyone that such a violation would have arisen,” Herling said. This only becomes apparent if the TO decides not to go forward with the project and, once pulled from the RTEP, PJM finds that a violation would occur. The project would then be converted to a baseline project.
Valerie Teeter, of FERC’s Office of Energy Policy and Innovation, asked PJM what that conversion process entails: “Does that violation kind of go back to the beginning of the stakeholder process? [Does it] go through the process that any other violation would? Is there a proposal window for solutions?”
“It’s all a matter of timing,” Herling responded. If the supplemental was identified three years ago and PJM realizes that absent the supplemental there will be a violation, construction on the project is likely to have begun. “At that point, we’re certainly not going to shut the project down so that we can hold a [proposal] window and see if a better project exists,” he said.
But, Herling said, that decision is “purely judgmental,” meaning there’s no bright line for when the RTO would open a proposal window to select the most cost-effective solution.
“Where it gets gray is in the middle,” when PJM notices a potential violation a year after a supplemental is proposed, for example. “Depending on the circumstances, we would likely say, ‘OK, put the brakes on, we’re going to open up a window’” for competitive proposals, Herling said. “Again, it’s very judgmental. It’s all going to be case-by-case based on the circumstances.”
Cunningham-Elmont
PJM reclassified the Cunningham line after Dominion revised its planning criteria last year. In its complaint, DP&L accused Dominion of exploiting what it called a loophole resulting from an Order 1000-related filing by PJM TOs that permits a portion of the costs of new 500-kV baseline projects to be shared by load-serving entities throughout the RTO.
Herling said that any party, including PJM, can identify whether a project might need to be converted from supplemental to baseline, especially in the case of aging infrastructure. However, “most often, my gut is it will be the transmission owner who will recognize the likelihood that the project should be converted. It is not always intuitive to anyone else.”
For the Cunningham rebuild, Dominion provided a “condition assessment” that the company said justified converting the project to baseline. Performing a condition assessment “is not the kind of thing that PJM could take as an initial step on their own,” Herling said. PJM then did its own evaluation based on Dominion’s work to confirm that it met the criteria for a baseline.
FERC staff asked why a proposal window was not opened for the need associated with Dominion’s planning criteria for aging infrastructure.
“That’s one we’re continuing to think our way through as a general matter,” Herling replied. “It’s challenging to us to justify going out and seeking other proposals when you’re going to have to tear the line down anyway, [and] the state would prefer you reuse the existing right of way.” In Cunningham’s case, PJM determined a violation would occur if it was taken out of the RTEP, so it needed to be replaced.
Hertzel Shamash, vice president of resource planning for DP&L, spoke up at this. “You [eliminate] any of the existing transmission lines … and you’re going to violate NERC standards, because you need that line. It wouldn’t be there if you didn’t need it.
“Regarding the open window: Yeah, you can build on existing rights of way, but someone can build it for a lower cost,” he said.
Maintenance, not Planning?
TO representatives pushed back at staff’s focus on the lack of a defined conversion process. The Cunningham case, in which a change in planning criteria led to a conversion, “is relatively rare,” said Steve Naumann, vice president of transmission and NERC policy for Exelon. “It’s a unique circumstance.”
Steve Naumann, Exelon responding to a question
“The drivers [of supplemental projects] can be so different, and many of them are management of the assets, which is not something that has been turned over to PJM,” Naumann said. “That has remained with the transmission owner: to manage their own assets, as opposed to transmission expansion. The TOs as a whole believe there’s no need — nor is there a requirement — to have a … hard and fast set of filed criteria for supplemental projects. Otherwise they wouldn’t be supplemental projects.”
Maintenance of the system is solely the purview of the TOs, said Frank “Chip” Richardson, manager of transmission regulatory and business affairs for PPL. “It’s excluded from PJM’s processes… You don’t see any processes where PJM evaluates the maintenance of the system.”
“We, by definition, don’t think supplemental projects are planning projects,” said Raja Sundararajan, vice president of transmission asset strategy and policy for American Electric Power. When AEP finds things that are broken and need to be fixed, it lets PJM know, he said. “Is that a planning process? No, that is not a planning process. That is fundamentally a maintenance and replacement of the assets.”
Maintenance is a business decision left solely up to the TO. “There’s a clear delineation of where planning is and when operation begins,” Sundararajan said.
FERC Unconvinced
FERC staff seemed unconvinced by these arguments. “I am not seeing that delineation,” replied Zeny Magos of FERC’s Office of Energy Markets and Reliability. “I personally do not see the difference between planning your transmission system and maintaining your transmission system.”
Mark Ringhausen, vice president of engineering for Old Dominion Electric Cooperative, also had complaints about the lack of process. He said one of ODEC’s neighboring TOs presented $250 million in supplemental projects last year, including rebuilds for aging infrastructure. He said PJM told ODEC the co-op didn’t have the ability to influence changes to other TOs’ supplemental projects because PJM said such projects are outside the RTO’s jurisdiction. “Clearly there is no process,” Ringhausen said.
Ringhausen cited FERC’s June 22 rehearing order on the planning and cost allocation requirements of Order 1000. In it, the commission said it read the PJM Operating Agreement as giving stakeholders “an opportunity at the early stages of each individual PJM transmission owner’s planning of supplemental projects (i.e., before each transmission owner actually identifies any potential supplemental project) to review the criteria, assumptions and models each individual transmission owner uses to plan supplemental projects” (ER13-198).
“Is that happening today?” Ringhausen asked. “Clearly … it’s not happening at the early stages.”
“RTEP is the Regional Transmission Expansion Plan,” Richardson countered. “It’s not the ‘Regional Transmission Maintenance Plan.’ There’s never been anything in PJM about how the transmission owners maintain their equipment.
“The definition of ‘supplemental’ is PJM does not need it,” he said. “They would never tell us to do it.”
Going Forward
Magos asked PJM if it thought it needed to update its Tariff or manuals to include a conversion process.
“My gut is we would probably want to take a look at updating the PJM manuals, which probably could be made to point to any number of existing practices that are in the Tariff, just to ensure they are applicable also,” Herling said. “Now if in the commission’s judgment that needs to be in the Operating Agreement or the Tariff, fine, we can certainly do that. But we would do the manuals first.”
“It would be very helpful, I think, for some of the people who have to pay for these projects to have a bright line in the Tariff that explains how you go from supplemental to regional transmission planning,” said Amy Fisher of Linden VFT. “That would be kind of an exclamation point that people should be very engaged in that process.”
FERC staff requested comments be filed by Dec. 10 on several issues discussed at the conference, including the process for reclassifying supplementals, stakeholder input on supplemental projects and the difference between transmission planning and transmission maintenance.
AUSTIN, Texas — The list of state regulatory commissioners in their 30s is a short one. The list of 31-year-old commissioners with five years of experience as economic regulators is even shorter.
So meet Montana’s Travis Kavulla, who is not only in his second term on the state’s Public Service Commission but also, as of last week, the chairman of the board and president of the National Association of Regulatory Utility Commissioners (NARUC).
Kavulla (Source: NARUC)
“It’s a real honor to have the confidence of my colleagues on the utility commissions, but it’s a particular honor to be in a leadership position,” he told RTO Insider in an interview.
Judging by the 1,000-person strong standing ovation the personable Kavulla received after his acceptance speech here Nov. 10, the fourth-generation Montanan appears to command the respect of his colleagues. Kavulla credited his involvement in several Western regional initiatives. He is co-chairman of the Northern Tier Transmission Group Steering Committee and is a member of the CAISO Energy Imbalance Market Transitional Committee.
“I raised my hand in the West and volunteered to head up western commissions’ exploratory efforts around a real-time energy market. These kinds of … enterprises can turn into talkathons on panel discussions, but that sense of initiative needs to be developed into practical actions.”
Kavulla is referring to the expansion of organized markets in the West. The process led to the Integrated System’s incorporation into SPP and CAISO’s expansion of its Energy Imbalance Market in the Western Interconnection.
“I’m delighted [the Western Area Power Administration] and Basin [Electric Power Cooperative] saw the benefit of participating in what I regard to be an efficient and liquid market” in SPP, he said. “It seems to be going very well. I have some concerns about seams issues, as most people do … but they’re not novel issues.”
A Western RTO?
WAPA’s Upper Great Plains region was the first federal power marketing administration to join an RTO. The dominant role of the Bonneville Power Administration, another power marketing administration, is one of the reasons there’s been reluctance to create an energy market in the Pacific Northwest, Kavulla said.
“Bonneville’s legal status as a federal power marketing administration was seen as an impediment to the creation of a market. WAPA reached an accommodation with SPP and that shows that concern to be overstated,” Kavulla said. “Bonneville could participate as a member of an RTO if it chose to, but there’s a very long way to go before that happens.”
Kavulla said that whether or not a Western RTO is formed “comes down to whether there is a trusting relationship between California and the other states, as well as the utilities and commissions realizing there’s a lot of money and a lot of efficiencies being left on the table.
“Once some of those governmental concerns about Cal-ISO are ironed out, I think a Western RTO will be achieved.”
Technological Changes
For now, Kavulla is firmly focused on his term as NARUC’s president and the issues facing economic regulators. Harkening back to the technological innovations that transformed the telecomm industry and that could do the same to the electric industry, he asked his acceptance-speech audience to focus on two important initiatives: greater involvement in and a better understanding of RTOs, and better pricing signals for customers who generate their own power or react to market signals by reducing demand.
“We need to understand that an RTO or an ISO can facilitate competition and the efficient use of resources that our consumers are already paying for,” he said in his prepared remarks. “[And] we need clear and economic price signals that do not overcompensate or undercompensate … customer-side actions.
“Regulation may not fix the price of electric power in RTOs … but regulations prescribe the definition of market products, the way in which those products are bid into and procured from the market, and even the amount of those products one needs to avoid penalties,” Kavulla said. “Most commissioners barely have time to keep up with our own dockets, but we owe it to ourselves to better understand these wholesale markets. NARUC, working together with the existing organizations of state regulators that advise RTOs and ISOs, can help in that role.”
Kavulla praised NARUC’s Electricity and Energy Resources and Environment committees’ work in creating a rate-design subcommittee that will report to Kavulla and his four fellow board members.
“I hope this subcommittee will work to create a practical set of tools — a manual, if you will — for regulators who are having to grapple with the complicated issues of rate design for distributed generation and for other purposes,” he said. “We have an ability, through a staff subcommittee, to produce a practical, expert and most importantly ideologically neutral guide that offers advice to the dozens of states who are grappling with this question, and yet do not have the resources to do it themselves.”
State, RTO Roles in Clean Power Plan
And then there’s the Environmental Protection Agency’s Clean Power Plan, a heavy topic of conversation here. EPA Administrator Gina McCarthy delivered NARUC’s keynote address, and several of the panels focused on the plan and its implications for the industry. (See related story, McCarthy Defends CPP, Asks for Continued Engagement.)
Kavulla said it is clear to him “most states, if not nearly all, will select a mass-based approach and open doors to trading in some form.”
“Then, the issue becomes the allocation of allowances and if you do trade, to whom do you open doors? Is it a regional approach?”
Asked about the role RTOs would have in helping implement regional trading programs, Kavulla noted that CAISO and the Canadian province of Quebec currently participate in a cap-and-trade program “that has no interconnection at all between them.”
“There’s a reason RTOs are going hither and yon and saying they’ll be an important part of this debate … that’s really a decision up to the states,” Kavulla said. “RTOs can come up with options that get away from a command-and-control solution for 111(d) compliance. As an economic regulator, I accept the proposition that whatever the environmental law may be, we should meet it in the most efficient manner … and that means trading.
“I hate to paint myself and other economic regulators as skeptical curmudgeons, but we’re the ones who have to be promoting economically efficient outcomes — which is going to be really hard work in the context of the Clean Power Plan.”
Former Journalist
Kavulla attributes his ability to get to the heart of the matter to his early career as a journalist. “It requires a talent for reading and boiling down a lot of complex materials and translating them into analysis,” he said.
A graduate of Harvard, where he majored in history, Kavulla edited the conservative political journal Harvard Salient and wrote a regular column for The Harvard Crimson, the school’s daily newspaper. Upon graduation, he landed an associate editor’s position at the conservative National Review and several editing and writing jobs, from “8,000-word essays to very short, newsy write-ups” on the economy, politics and culture.
Kavulla returned to his hometown of Great Falls in 2009, intent on finishing a book on American evangelicals’ influence on the African church and continuing his freelance career. However, he wound up “being sucked in the vortex of local politics,” helping elect a city commissioner to undo the city utility’s “ill-conceived” fixed-rate electricity contracts.
Discovering that he enjoyed the process and understood the issues, Kavulla ran for the Great Falls area’s seat on Montana’s five-member PSC in 2010, winning election by 28 percentage points. Kavulla was re-elected last year, and will be term-limited in 2018.
After that? A Republican, he is already being mentioned as a potential FERC commissioner. Both Commissioners Tony Clark and Colette Honorable served as NARUC president before moving to Washington.
“I really don’t know,” he said with a laugh.
No worries. There’s much to do until then.
Other NARUC Officers, Board Elections
Pennsylvania Public Utility Commissioner Robert Powelson was elected first vice president and John Betkoski, vice chair of Connecticut’s Public Utilities Regulatory Authority, was elected second vice president.
Appointed to NARUC’s board of directors were: Judith Jagdmann of the Virginia State Corporation Commission; Ellen Nowak, chairman of the Wisconsin Public Service Commission; New Hampshire Public Utilities Commissioner Robert R. Scott; and Brien J. Sheahan, chairman of the Illinois Commerce Commission.
The NARUC board also confirmed Michigan regulator Greg White as executive director effective Dec. 1. He will replace Chuck Gray, who is retiring.
NARUC immediate past President Lisa Edgar thanked Gray for “37 years of service, regulatory intellect and camaraderie.”
“He has left a lasting imprint on the association,” she said.
White served on the Michigan Public Service Commission for more than five years after working in a variety of staff positions with the agency since 1987. He holds a Master of Public Administration from Grand Valley State University and a bachelor’s in resource development from Michigan State University.
Critics of Exelon’s proposed acquisition of Pepco Holdings Inc. on Wednesday questioned the timing of a $25 million naming rights deal that D.C. Mayor Muriel Bowser finalized with Pepco days before dropping her opposition to the merger.
Pepco agreed in July to sell district property in the Buzzard Point area for the construction of a soccer stadium for D.C. United. On Sept. 18, Pepco signed a sponsorship deal in which it will pay the district $25 million for the right to rename a street near the stadium “Pepco Place.” The agreement also gave the company the option to install “Pepco Park” signs near a proposed practice facility for the NBA’s Washington Wizards in Southeast D.C.
On Oct. 6, Bowser announced that her administration had reached a settlement with Exelon and Pepco and would support the merger. She previously had praised the D.C. Public Service Commission’s unanimous rejection of the deal in August.
In a press conference at the site of the soccer stadium, representatives of Public Citizen and the Chesapeake Climate Action Network released a letter calling on the District Board of Ethics and Accountability to “evaluate these two high-stakes situations to ensure that there was no impropriety, collusion or unethical conduct of any kind.”
That office did not respond to a request for comment on how the appeal would be handled.
The groups also shared a Freedom of Information Act request they had submitted to the mayor’s office asking for all internal correspondence among the administration, Exelon and Pepco.
Mike Tidwell, CCAN, at protest (Source: Chesapeake Clean Action Network)
“D.C. residents deserve to know if pay-to-play politics or quid pro quos played any role in advancing this massive corporate merger,” said Craig Holman, a lobbyist with Public Citizen.
Bowser was on a trade mission in China. In response to the allegations, her communications director, Michael Czin, said, “Pepco, as a majority land owner at Buzzard Point, has been in contact with the district government regarding a soccer stadium for years. The sponsorship agreement stemmed from that negotiation, which was unrelated to the merger.”
Pepco has said discussions involving the naming rights began in 2013.
“It’s clear the small vocal minority who continue to oppose the merger are becoming increasingly desperate in their last-ditch attempts to disrupt it,” Pepco spokeswoman Myra Oppel said. “They are deliberately ignoring the facts and will say just about anything to distract from the substance of the merger and to serve their special interests.”
Members of the public who aren’t a party to the case will have a chance to speak at hearings before the PSC Nov. 17-18.
At the press conference, the groups also pointed to the pro-Bowser “FreshPAC” as evidence of “pay-to-play” politics. Officials with the independent political action committee told The Washington Post last week that the group, while legal, had become a “distraction” and would be disbanded.
The Post reported that Pepco has declined to say if the company had been asked to contribute to the PAC.
New York transmission owners filed a proposed settlement with FERC on Nov. 5 establishing the cost allocation and rate of return for three transmission projects intended as contingencies for the potential closure of the Indian Point nuclear power plant in Westchester County (ER15-572-004). (See Divided FERC Trims ROE on NY Tx Projects, Orders Hearing.)
The proposal settles the revenue requirements, including the return on equity and the inclusion of adders, of New York Transco, the organization of investor-owned utilities in the state that will develop and own the Transmission Owner Transmission Solutions (TOTS) projects.
“This settlement agreement results in a total ROE (10%) for the TOTS projects that is lower than the base ROE (10.60%) proposed by the applicants and supported by the applicants’ filing,” the settlement says.
The agreement leaves intact the 50-basis-point adder for the TOTS projects, as granted by FERC, for costs up to $228 million. The agreement says the adder accounts for benefits to customers, including congestion relief.
That resolves the New York Public Service Commission’s objection to having a separate adder for the transcos’ participation in an RTO and the transcos’ inclusion of additional adders for other ratepayer benefits, according to the settlement.
The agreement also includes transmission owners New York Power Authority and Long Island Power Authority as signatories. Because they are public authorities, they cannot join the NY Transco organization without a law allowing them to form a subsidiary company. Also agreeing to the settlement are the New York Public Service Commission; the New York State Department of State Utility Intervention Unit; New York City; the New York Association of Public Power; the Municipal Electric Utilities Association of New York; and an unincorporated group of about 60 industrial, commercial and institutional energy consumers.
The cost allocation is “voluntarily agreed to by all participants who will bear the costs of the TOTS projects under the NYISO [Tariff],” according to the settlement.
NY Transco’s members and their allocations are: Central Hudson Gas and Electric (5.99%); Consolidated Edison of New York and Orange and Rockland Utilities (63.18%); National Grid’s Niagara Mohawk Power (12.16%); and New York State Electric and Gas and Rochester Gas and Electric (10.12%).
The agreement does not include two AC projects in the FERC order from April: the estimated $1 billion Edic-Pleasant Valley 345-kV line and the $246 million Oakdale-Fraser 345-kV line.
Rehearing requests for them will remain pending but held in abeyance, as those projects may be subject to further action by NYISO, according to the settlement. The ISO could issue a “viability and sufficiency assessment,” which would restart their settlement negotiations.
VALLEY FORGE, Pa. — A military blimp that broke free from the Aberdeen Proving Ground in Maryland on Oct. 28 and dragged a steel tether some 125 miles before deflating in Montour County, Pa., caused surprisingly little damage to power lines, PJM’s Chris Pilong told the Operating Committee last week.
US Military aerostat blimp (Source: Defense Department)
“We actually didn’t see any impact until it got to PPL territory,” he said.
There, around 2 p.m., it knocked out one 500-kV line, and the two 230-kV lines, in the Sunbury-Susquehanna and Montour area.
In addition, three 69-kV sub-transmission lines were felled by the runaway airship’s several-thousand-foot-long tether, causing a blackout for as many as 35,000 customers.
“Despite the odd cause … there was no permanent, lasting damage,” he said. “Just an unusual afternoon.”
William Skumanich of PPL said those in the company’s control room at the time were flummoxed.
“We in the control center did not know what was going on, and all of a sudden we get this string of outages,” he said. “It was really a mystery. We really thought it was a tornado.”
PPL spokesman Paul Wirth said power was restored to affected customers by midnight, and all damage was repaired later the next day.
ComEd Open-Loop Interface Created
PJM has introduced a change to the ComEd reactive transfer interface. The closed-loop interface, implemented in June 2013, is composed of all ComEd tie lines and is used to control reactive issues during summer peaks, when the zone is importing power.
The interface is being changed to an open loop of six of the ComEd extra-high voltage lines on the zone’s eastern border. Dubbed CE-EAST, it will go into effect March 1.
The change is being made so that certain generators in MISO can help with voltage issues in the Chicago area.
Operational impact will be minimal, PJM said, and the change will be reflected in Manuals 03 and 37.
Winter Reserve Target Same as Last Year
The committee endorsed a 27% winter reserve target, the same value as last year.
The target is based on unit summer ratings and expressed as a percentage of the forecasted weekly peak load. It is derived from simulations of the 13-week winter period.
PJM operations will seek to maintain the 27% margin in scheduling generator maintenance outages.
Concept of ‘Soak Time’ Parameter Introduced
PJM initiated discussion with stakeholders over a proposed new parameter for Capacity Performance units called “soak time,” with the goal of having a concept in place by June 1.
PJM’s Tom Hauske introduced the proposed definition as “the minimum number of hours a unit must run, in real-time operations, from the time the unit is put online (breaker closure) to the time the unit is at its economic minimum or dispatchable.”
Units with a soak time greater than their minimum run time would be able to petition for a unit specific parameter adjustment.
Committee Chair Mike Bryson said the concept primarily would apply to fossil-fired steam units and would not affect penalty assessment hours under the new Capacity Performance product.
ComEd SPS Changes in the Works
Alan Engelmann of Commonwealth Edison gave the following updates regarding special protection systems (SPS):
Byron Unit: A new 345-kV line between Station 6 Byron and TSS 144 Wayne, expected to be in service by June 2017, will resolve the stability issues for which the Byron SPS was designed. On completion of the line, the Byron Unit Stability Trip Scheme will be removed. As part of the project, a new breaker was installed in October.
Powerton 345-kV bus and Powerton Unit: In a project targeted for completion in 2017, a reconfiguration of the Powerton 345-kV bus and breaker replacements will allow the removal of the Powerton SPS when the station is in normal configuration.
Northbrook/Highland Park Transfer Trip: This SPS prevents thermal overloads and low voltage. A normally closed bus tie line will be installed at Highland Park by December, and the SPS no longer will be needed.
VALLEY FORGE, Pa. — The Planning Committee last week endorsed comprehensive revisions to Manual 19 to incorporate changes to the load forecast model.
The changes account for trends in equipment and appliance saturation and energy efficiency; revise weather variables; update weather station assignments to zones; and modify the weather normalization procedure.
Members decided to remove a change that would have added distributed solar generation to the model this year, saying they wanted to see more data on its predicted effect first.
PJM’s John Reynolds said that in response to requests for more information about how the new load model was developed, PJM will be producing a white paper on the subject early next year.
Steve Herling, PJM vice president for planning, encouraged the group to approve the changes, carving out the solar section, instead of holding them up.
“Our concern obviously is that we don’t want to get behind the curve, which we did to a degree with energy efficiency,” he said.
Panel Re-examining Reserve Requirement Study
The Resource Adequacy Analysis Subcommittee will be holding two education sessions as part of its effort to re-examine all modeling assumptions for the 2016 Reserve Requirement Study.
The first is scheduled for 1 to 4 p.m. on Nov. 24. The second is 9:30 a.m. to 12:30 p.m. on Dec. 9. Both will be held in person at the Valley Forge campus and via WebEx.
The subcommittee will schedule meetings as needed through the first quarter of next year in order to finalize RRS assumptions and bring them to the committee for endorsement in April.
PJM’s Tom Falin said it is the first re-evaluation of the process in about seven years. Planners are focusing on the full study to underscore that the installed reserve margin “is not the most important output from the study,” Falin said. Members had questioned the recent increase in the IRM, saying it seemed counterintuitive under the new Capacity Performance model. (See “IRM, FPR Rising; PJM Methodology Challenged” in PJM Planning Committee Briefs.)
Falin said the RAAS discussion will focus on three drivers: the selection of PJM and world load models, the development of capacity models and the representation of the world area. It also will consider the impact of CP on RRS assumptions.
Two More Units Headed for Deactivation
Two generating units have applied for deactivation in January.
Perryman Unit 2, a 51-MW facility in the BGE transmission zone, will be deactivated Jan. 1.
Interim operating measures have been identified until a baseline upgrade is completed there by June 2017. That upgrade, a new 115-kV switching station, is expected to cost $26 million, the cost of which is being designated to Baltimore Gas and Electric.
The second unit to be decommissioned is the 2-MW Pottstown landfill, in the PECO transmission zone. Landfill owner Waste Management said that flows of landfill gas have declined significantly since the landfill was closed in 2005 and that there is no longer enough gas to drive the turbine. It will be deactivated Jan. 15. No reliability impacts have been identified by the closure.
VALLEY FORGE, Pa. — The Market Implementation Committee last week unanimously approved a problem statement to consider revisions to the parameter limited schedule (PLS) exemption process.
Bob O’Connell, who presented the issue on behalf of PPGI Fund A/B Development, said Tariff changes made in 2012 have made it more difficult to obtain exceptions to default PLS values, limitations imposed on generators’ minimum run times or other elements of cost-based offers.
O’Connell took issue with the “inflexible deadline” for long-term exceptions, which, he said, “does not recognize various changes that may take place on the market participant’s side that may result in the need to get around the Feb. 28 deadline.”
For example, he said, he has clients currently testing units that might not be ready by Feb. 28. “They don’t know if they should apply for anything,” he said.
There also are challenges with the resolution that has been proposed, he said, which is to seek a waiver from FERC. First, there is no guarantee the commission will rule, he said.
“Second, if a market participant is seeking an exception, right now the market participant works with the Market Monitor and PJM to determine whether, one, the exception is merited and, two, what the numbers should be,” he said. Once FERC is approached, he said, “Everybody can be involved, even if they don’t have the information.”
“What we’re seeking to do is start up the stakeholder process to rethink what’s on the table right now and come up with something that provides an administratively efficient process.”
Debate Continues over Confidentiality of Information
The committee continued to debate allowing PJM to make public certain types of data, such as uplift payments, demand response deployments, generator outages and cleared capacity resources. The changes would modify Manual 33: Administrative Services. (See PJM Stakeholders to Study Relaxing Confidentiality Rules.)
Jim Benchek of FirstEnergy said his company is most concerned with two of the six categories: details about individual generation outages and cleared capacity resources.
Regarding the outages, he said, “As a resource owner, we believe that is our data, and we really don’t want to release it to make it public.”
If PJM, the market seller and the Independent Market Monitor agree the information is not confidential, he said, “then it would be OK to release that data.”
In addition, he said, outages carry a variety of implications, including Capacity Performance penalties, and information about them might lead some to speculate about the health of a company. Likewise, releasing information about cleared capacity resources provides a window into a company’s position in the market, he said.
A number of suppliers echoed his concerns.
Monitor Joe Bowring said he had concerns about proposed changes to the capacity resource section of the manual, which would allow PJM to release the identities of resources that clear the third Incremental Auction.
“We don’t think supply curves in the capacity market should be made public,” Bowring said. “The information is very persistent from year to year. It supports collusion.”
Compromise Offered on Masking FTR Ownership
DC Energy’s Bruce Bleiweis, who has been leading a rocky effort to mask the ownership of financial transmission rights, said he was willing to offer a compromise: that they be kept private for 90 days.
At a September meeting of the MIC, Bleiweis garnered only 61% approval of his problem statement — an indication that he may have trouble winning the two-thirds majority needed for a rule change. (See “PJM to Consider Masking FTR Ownership” in PJM Market Implementation Briefs.)
At that meeting, Bleiweis had asked PJM to look into whether it discloses the ownership of its other market products. PJM’s Tim Horger confirmed last week that the RTO does not.
“In other types of markets, participant info is not posted out there,” Horger said. “PJM can support a change for removing it, but [we] want what the stakeholders want. We don’t have a strong interest one way or the other.”
Bowring reiterated his support for the status quo.
“We think the current release of ownership information makes sense, and we don’t see a reason for your additional compromise proposal,” he said.
Bleiweis said FTR owners should be able to expect the same treatment as other market participants.
“We’re not looking for less transparency; we’re looking for consistency,” he said.
“Our biggest concern is there are instances where you have multi rounds of auctions, and we were hoping that the membership, the Market Monitor and PJM would agree that releasing that information intraround — so that you see the ownership after round one, before round two — that you shouldn’t reveal that kind of confidential information.”
The Department of Energy on Thursday issued the final environmental impact statement for the New England Clean Power Link, recommending approval of a presidential permit for the cross-border project, which would transmit 1,000 MW of Canadian hydropower into New England.
The 154-mile, $1.2 billion HVDC project was proposed in early 2014. The final report includes changes made in response to comments on the department’s draft EIS in June. (See Lake Champlain Cable into New England Progresses.)
Among the changes were updated technical information; alternatives included in the U.S. Army Corp of Engineers 404 permit; additions to water resource analyses requested by the Environmental Protection Agency; and details on the project construction period and impacts on the long-eared bat and wetlands.
The merchant line, which would be entirely underwater or underground, is still undergoing permitting review by Vermont.
Transmission Developers Inc. New England, a unit of The Blackstone Group, anticipates that all major federal and state permits will be granted by the end of the year and the project would be in service in 2019. Ninety-eight miles of the cable would be buried under Lake Champlain, and most of its land-based route would be underground to Ludlow, Vt.
TD-NE began an open solicitation on Oct. 15 for customers to buy capacity on the line, with expressions of interest due by Dec. 4.
“We are confident that, once built, the New England Clean Power Link will deliver environmental and economic benefits to the people of Vermont and New England and do so in a way that minimizes impacts to communities and helps meet the region’s growing energy and environmental challenges,” TDI-NE CEO Donald Jessome said in a statement.
The Northern Pass line, which would deliver 1,090 MW to New England from Canada, has an agreement between its U.S. sponsor, Eversource Energy, and Hydro-Quebec. That $1.6 billion project has generated much more controversy because most of it is above ground. It also is not as far along in the regulatory process as the Clean Power Link. (See Northern Pass Files for Siting Approval, Revises Cost.)
