The indefinite mothballing of a 470-MW coal-fired plant has reduced ERCOT’s “pretty scary” reserve margin of 8.1% to 7.4%, prodding the Texas Public Utility Commission into ordering several market changes.
The PUC on Thursday directed ERCOT to tweak its operating reserve demand curve (ORDC), which provides a price adder during periods of generation scarcity, and to proceed with implementing real-time co-optimization.
“I was already concerned, and with [this plant] coming out, it’s heightened my concerns,” said PUC Chair DeAnn Walker, whose “pretty scary” comment has been making the rounds in the trade press. She made the comment following the December release of ERCOT’s last capacity, demand and reserves (CDR) report, which revealed the 8.1% reserve margin. (See ERCOT Predicts Tight Reserve Margin for 2019.)
Shortly before the open meeting began, ERCOT announced it had completed a reliability analysis and determined that the city of Garland’s Gibbons Creek Generating Station was not required to support system reliability. That clears the way for the city to indefinitely suspend the plant’s operations, effective June 1.
ERCOT representatives assured the PUC that it can meet demand with the new historically low reserve margin by following its emergency operations procedure. That would entail procuring emergency response service, voltage-reduction measures and releasing reserves.
“There’s some talk that 7.4% is not that big of a deal,” Walker said. “I believe you can absolutely run this system in a reliable manner, but when you hear 7.4%, does that give you a lot of comfort?”
“At that reserve margin level, it’s likely that we will have to take advantage of those additional resources,” replied Dan Woodfin, ERCOT’s senior director of system operations. “We will likely have to do that on a number of occasions this summer, but there’s not an indication at this point in time that we will have to implement rotating outages.”
Woodfin did not discount the use of rotating outages in the case of extreme weather, low wind output or forced generation outages.
“Again, I have full confidence in ERCOT managing and running our system, and if we have a large unit trip this summer on the hottest day of the year, I think we can manage this,” Walker said. “But I also believe there are things this commission can do.”
ERCOT’s Dan Woodfin (left) and Warren Lasher address the Texas PUC.
In a memo filed shortly before the PUC’s open meeting began, Walker suggested making a 0.25 standard deviation shift in the loss-of-load probability calculation and using a single blended ORDC curve as soon as practicable. She suggested a second shift of 0.25 in the standard deviation next year.
Both Sides
The change would lead to the ORDC’s more frequent use, and at higher levels.
Walker said the blended ORDC would also increase the development of demand response, distributed generation and self-generation, and could lead to delays in pending retirements and other units returning to service much more quickly.
Writing that real-time co-optimization would bring economic and operational benefits to the market, Walker also proposed that PUC staff bring back to the commission’s Feb. 7 meeting a list of policy issues for stakeholder comment and asked that ERCOT provide a high-level implementation plan and timeline.
Walker said including marginal losses in the security-constrained economic dispatch is not “worth the implementation cost and market disruption.”
Commissioners Arthur D’Andrea and Shelly Botkin agreed with Walker’s proposals, though Botkin said she was not prepared to take the second step with the ORDC just yet.
ERCOT staff told the commission they could take the ORDC change to the grid operator’s Technical Advisory Committee on Jan. 30 and to the Board of Directors on Feb. 12. That would enable ERCOT to implement the revised ORDC by April.
“I think there are a lot of good arguments on both sides,” D’Andrea said. “I think all of us agree we’re going to stay committed to market principles and let our energy-only market work. I think acting now is prudent.”
| Tom Harpool Collection, University of North Texas Special Collections
Vistra Energy released a statement in support of the actions, saying “proper price signals must be sent to incentivize investment in maintaining the existing generation facilities and developing new, more efficient technology” as the Texas market evolves from older, less-efficient technology.
In performing its transmission reliability assessment of Gibbons Creek, ERCOT said “the tools under its emergency procedures are adequate in maintaining grid reliability.”
Garland Power & Light in December submitted a notification of suspension of operations for the 35-year-old unit, which is operated by the Texas Municipal Power Agency. It had been operating seasonally since 2017 and returned to mothballed status in October.
WASHINGTON — FERC devoted most of its monthly open meeting Thursday to honoring recently deceased Commissioner Kevin McIntyre, with Chairman Neil Chatterjee delivering a lengthy, emotional eulogy that drew tears from some staff members in the audience.
Chatterjee went beyond merely praising McIntyre’s character and work at the commission. Instead, for about half the commission’s 50-minute meeting, he recalled, sometimes with a shaky voice, how he and McIntyre bonded during their time on the commission together, forming a brotherly relationship.
The chairman said that in the weeks since McIntyre’s Jan. 2 death, many people have related to him that McIntyre told them that “he loved me like a brother.”
“And that’s classic Kevin, that he would never have said those words to me directly, because he didn’t like to emote like that. He would have said something to the effect of, ‘I love you like my much shorter brother. I love you like my dark-haired brother.’
“But I’ve heard it from enough people that even though I didn’t hear it directly, I know he meant it, and I love my brother. And I am going to work with my colleagues to ensure that we execute on the legacy that he put into motion, not just for him and in his memory, but because he was an earnest public servant that genuinely wanted to do the right thing.”
McIntyre, 58, died after an 18-month battle with brain cancer. Sworn in as chair in December 2017, he relinquished the position to Chatterjee on Oct. 24 last year as his health deteriorated. (See FERC’s McIntyre Loses Cancer Battle.)
Chatterjee, who had previously served as chair for four months before McIntyre’s arrival, told of how he had felt overwhelmed by all the issues before the commission and reached out to McIntyre for advice.
According to Chatterjee, McIntyre told him over dinner, “‘Neil, I’m just a Jones Day lawyer. You are the chairman of FERC. These are your decisions to make, and it is incumbent upon you to lead. … Whatever decisions you and your colleagues make, I will work to push them forward. … Just do what you think is right; put country over party and the public good over politics, and you’ll be just fine.’”
About a month after McIntyre joined, FERC unanimously rejected the Department of Energy’s Notice of Proposed Rulemaking for the commission to order RTOs and ISOs to compensate the full operating costs of generators with 90 days of on-site fuel (RM18-1).
Collegial, Nonpartisan
Chatterjee, a former energy adviser to Senate Majority Leader Mitch McConnell (R-Ky.), has been candid about how McIntyre helped him grow professionally from being a partisan aide to independent regulator. He has said that he was initially sympathetic to the NOPR because of the aid it would provide to coal country, including his home state of Kentucky. (See Returning Chair Pledges to Protect FERC’s Independence.) As chair, he pushed for a short-term plan to rescue as many plants as possible while the commission did additional fact-finding.
At another dinner between the two after the commission’s Jan. 8, 2018, ruling, McIntyre praised Chatterjee for his leadership during his tenure as chair on the issue.
Chatterjee said he was incredulous. “I said, ‘Kevin, that’s ridiculous. I’m self-aware enough to know that I made a number of mistakes. I threw up all over myself throughout this and botched this at myriad points.’ And he said, ‘Stop. No, you did not. You were confronted with a difficult situation. The secretary of energy asked us a very complex and important question. You tried to do the right thing.’ …
“He didn’t need to do that,” Chatterjee continued. But “that is the mark of a strong leader: someone who recognized that his colleague was feeling down and went and bucked me up and said, ‘Hold your head up high, and let’s continue to move forward together.’”
The two further bonded attending Georgetown Hoyas and Washington Nationals games, and over promoting awareness of Down syndrome, which McIntyre’s youngest child has.
Chatterjee also recalled how McIntyre’s wife, Jennifer, called him the day he was promoted back to the chair. According to Chatterjee, she said, “‘I know you hate this. I know you didn’t want this, and you are wracked with guilt. Stop it. The only thing of happiness that Kevin is taking from this difficult situation is the knowledge that his friend is going to have this opportunity. … Don’t go moping around; don’t hang your head; don’t feel sorry for yourself and for us. You need to man up and lead.’”
Commissioners Cheryl LaFleur and Richard Glick also praised McIntyre, echoing Chatterjee’s remarks about his dedication to nonpartisanship and collegiality.
“Sometimes it seems kind of rote to suggest that we should take heart in an experience such as this and vow to be better people,” Glick said. “But I think we would do well to take a page from Kevin’s book and focus every day on upholding the commission’s collegial, nonpartisan tradition. The coverage in the press sometimes seems to focus on the horse-race aspect of what we do: what commissioners are voting, how we are voting, or whether there’s an ‘R’ or ‘D’ next to our name. In my opinion, that’s not an accurate picture of how the commission functioned under Kevin, or how it functions today.”
On the morning after McIntyre’s death, “there was a sharp pang of loss and that hollow feeling all around the building and in everyone you talked to,” LaFleur said, “because it was the feeling that our best and our brightest had been taken away from us.” She said she appreciated McIntyre’s legal judgment, commitment to the rule of law and his concern for FERC even while he struggled with his health. She also “loved his vocabulary. He always used his unique words that properly summed up whatever he wanted to say.”
Chatterjee concluded his speech by announcing that FERC’s main meeting room would be named in McIntyre’s honor, with details of the dedication to be announced on a later date.
FERC on Thursday ordered hearing and settlement procedures on a complaint by the Louisiana Public Service Commission alleging that its ratepayers are being overcharged by an Entergy subsidiary that sells power from the Grand Gulf nuclear plant (EL18-204).
The ruling effectively reinstates a portion of a complaint FERC had earlier dismissed for lack of evidence over System Energy Resources Inc. (SERI), an Entergy subsidiary that sells Grand Gulf’s output to four Entergy operating companies: Entergy Arkansas, Entergy Louisiana, Entergy New Orleans and Entergy Mississippi.
Grand Gulf Nuclear Station | Entergy
In August, FERC set for hearing and settlement the PSC’s complaint that SERI’s return on equity of 10.94% was based on outdated data that did not reflect current capital markets (EL18-142). (See FERC Sets La. Entergy Complaint for Settlement.)
But the commission rejected the PSC’s complaint over SERI’s capital structure, saying the regulators had not demonstrated that it was unjust and unreasonable.
The PSC had contended that SERI’s equity ratio of 64.9% was “unusually rich” and that it was cross-subsidizing more highly leveraged activities while transferring most of its risk to the four operating companies.
FERC said the PSC had not presented any evidence that SERI does not meet the requirements of the federal commission’s three-part test for determining whether to use an operating company’s actual capital structure: whether the operating company issues its own debt without guarantees, has its own bond rating and has a capital structure within the range of structures approved by the commission.
The PSC responded to the Aug. 24 order a month later with a new complaint that offered evidence that SERI did not meet the three-part test.
It provided records that it said showed SERI’s debt is guaranteed by its parent and the operating companies. It also contended that SERI is a shell company with no employees and that each of its corporate officers is an executive officer of Entergy. It said SERI’s equity ratio should be reduced to 35.8%, or at least no higher than 49%, the equity ratio of SERI combined with the operating companies.
FERC rejected Entergy’s contention that it had already decided the merits of the capital structure allegations.
“The language in the Aug. 24 order indicated that the allegations in the complaint in docket No. EL18-142-000 concerning capital structure did not establish a prima facie case to justify setting that issue for hearing. Thus, there was no hearing litigating SERI’s capital structure … and the Aug. 24 order cannot be considered an ‘on the merits’ judgment on SERI’s capital structure,” the commission said.
FERC said it will let the chief administrative law judge decide whether to consolidate this proceeding with docket EL18-142.
Rehearing Denied
Separately, FERC on Thursday also rejected the PSC’s request for rehearing of its May 17 order regarding Entergy’s “bandwidth” calculation for a seven-month period in 2005 (EL01-88-020). (See FERC Affirms Rulings in Entergy Bandwidth Dispute.)
The calculations were used to equalize production costs among Entergy’s operating companies.
WASHINGTON — Senate Democrats pressed acting EPA Administrator Andrew Wheeler on the agency’s efforts to reverse Obama administration policies on vehicle and power plant emissions Wednesday, complaining he failed to demonstrate a sense of urgency to address climate change.
Wheeler was nominated by President Trump on Jan. 9 to replace Scott Pruitt, who resigned as administrator in July.
In a two-and-a-half-hour confirmation hearing before the Environment and Public Works Committee, Wheeler was repeatedly challenged by Democrats over EPA’s dismantling of the Clean Power Plan and its plan to weaken fuel economy standards for vehicles. But with only 47 votes, Democrats and the two independents who caucus with them will be unable to block Wheeler’s confirmation.
About a quarter of the audience in the small hearing room wore the red T-shirts of the Moms Clean Air Force and Wheeler’s opening statement was difficult to hear over the shouts of “Shut down Wheeler, not the EPA!” from protestors outside the room. The shouts began after two protestors inside the room were ejected.
Republicans praised Wheeler’s nearly two decades of experience at EPA and at the Senate committee, which oversees the agency. Wheeler began his EPA career during the George H.W. Bush administration and later served as staff director and chief counsel to Republicans on the committee.
“I think that’s really strong qualifications for this job,” Sen. Dan Sullivan (R-Alaska) said. “You come highly, highly qualified.”
Republicans also praised EPA’s efforts under Wheeler and Pruitt to clean up long neglected toxic waste dumps and to tighten regulations to protect children from lead. Wheeler called himself a “conservationist,” saying, “I am an Eagle Scout. I’m an avid camper [and] hiker.”
But the nominee found little support among Democrats. Although several praised him for being more responsive to their offices than Pruitt, Sen. Tom Carper (D-Del.) said “his policies are almost as extreme.”
Sen. Sheldon Whitehouse (D-R.I.), pressed Wheeler on his work as a lobbyist for coal magnate Robert Murray, suggesting he had been disingenuous when he previously minimized his role in Murray’s “action plan” to save coal-fired electric generation. Aides displayed blow-ups of photos of a meeting at which Murray and Wheeler discussed the plan with Energy Secretary Rick Perry. (See Photos Show Murray’s Role in Perry Coal NOPR.)
In August, Wheeler announced EPA would replace the Obama Clean Power Plan with the Affordable Clean Energy (ACE) Rule, which defines the “best system of emission reductions” as heat-rate efficiency improvements that can be achieved at individual coal plants. The CPP set state emissions limits and encouraged switching to natural gas and renewables. Wheeler cited EPA projections that ACE will reduce U.S. power sector CO2 emissions up to 34% below 2005 levels, but Democrats said it will allow higher emissions than the CPP. (See EPA: CPP Replacement Could Boost Coal-Fired Power by 6%.)
In December, EPA proposed changing its cost-benefit calculations to eliminate the “co-benefits” of reducing pollutants other than those being targeted. Had the proposed methodology been in place in 2011, EPA said, it would have prevented the Mercury and Air Toxics Standards (MATS), which pushed many coal generators into retirement.
Sen. Ben Cardin (D-Md.) said he didn’t understand why EPA was seeking to change its cost-benefit methodology, saying “it seems to me the mercury standards have worked.”
Wheeler said EPA had to re-evaluate the rules in response to a Supreme Court ruling but said he didn’t expect the change to affect mercury emissions.
“Under our preferred option, I do not believe there would be a weakening of the mercury standards at all as far as the equipment that has already been deployed and implemented across the board,” Wheeler said. “I get accused of rolling back the Clean Power Plan. I don’t think you can roll back a regulation that never took effect. And on MATS, I don’t think you can roll back a regulation that’s been fully implemented. I honestly don’t believe that equipment will be turned off or removed under our proposal.”
Carper was skeptical. He said Delaware would be in noncompliance for nitrogen oxide even if it eliminated all pollution from vehicles and businesses because it is downwind from several coal-fired generators in Pennsylvania and West Virginia. “The cruel irony is each of those plants had installed the technology to stop the pollution. … They turned it off. They still have it turned off. And when we [asked] EPA to do something about it, you declined. So, forgive me for being concerned and cautious on this front.”
In response to questioning by Sen. Bernie Sanders (I-Vt.), Wheeler agreed that the climate is changing and that humans have an impact on it, saying “I wouldn’t use the ‘hoax’ word” as Trump has used to dismiss climate change.
“Do you agree with the scientific community that climate change is a global crisis that must be addressed aggressively?” Sanders pressed.
“I believe that climate change is a global issue that must be addressed globally,” Wheeler responded. “I would not call it the greatest crisis. … I consider it a huge issue that has to be addressed globally.”
Wheeler also conceded the forest fires that have charred parts of California had “some relation” to climate change but said “the biggest issue is forest management.”
Sen. Jeff Merkley (D-Ore.) rejected Wheeler’s contention, saying “the reason these fires are so much longer [is] because the summer season is so much hotter and longer.”
“Our entire ecosystem … our fishing, our farming, our forests, are at grave risk.”
RENSSELAER, N.Y. — The NYISO working group charged with shepherding carbon pricing into New York’s wholesale electricity market kicked off its efforts Tuesday by taking up the issue of how import and export transactions would be handled under the pricing scheme.
A task force created in October 2017 by NYISO and the New York State Public Service Commission worked for more than a year developing a proposal to price carbon into wholesale markets. Last month, it turned the proposal and final details over to the ISO’s stakeholder process. (See IPPTF Hands off Carbon Pricing Proposal to NYISO.)
Ethan D. Avallone, NYISO senior energy market design specialist, showed the Market Issues Working Group (MIWG) several hypothetical transactions, pointing out that his examples “had to be extreme to show the effects of under- or overestimating the real-time carbon charge.”
A carbon charge or credit would apply only to transactions that actually flow in real time, and to external transactions such that they compete with internal resources and each other as if the ISO was not applying a carbon charge to internal suppliers — that is, on a status quo basis, Avallone said. (See NYISO Plan Revises Treatment of Carbon-Free Resources.)
A market participant intending to import into the New York Control Area (NYCA) will sell power at the proxy generator bus for the applicable control area in the NYISO market. | NYISO
To calculate locational-based marginal prices, the examples in the presentation focused on prices at one NYISO proxy generator bus located outside the New York Control Area to represent a typical bus in an adjacent control area. There may be more than one proxy generator bus at a particular interface with a neighboring control area to enable the ISO to distinguish the bidding, treatment and pricing of products and services at the interface.
Imports into the NYISO market are paid the proxy generator bus price for the applicable external control area. For example, an import with costs of $40/MWh in the PJM market could sell at the $50 PJM Keystone Proxy Generator Bus price in the NYISO market for a potential net revenue of $10/MWh.
Several stakeholders at the meeting said they wanted better real-time data from the ISO, possibly using a unit-specific, rather than aggregated, approach.
“The reason we landed on this more aggregated approach is because we wouldn’t be able to tell whether a unit-specific one is representative,” Avallone said, adding that the fundamental question about what approach to take had been fully aired in the stakeholder process last year.
Seth Kaplan of EDP Renewables, the largest wind generator in the state, said his company had no position on the matter but suggested the ISO ask for market proposals for a unit-specific approach from those who were advocating one.
Howard Fromer, director of market policy for PSEG Power New York, offered that the ISO could provide day-ahead carbon data to help traders to better ascertain the right carbon adder in order to plan their bids.
“We would settle on the real-time LBMP,” Avallone said in explaining the ISO’s choice not to provide day-ahead data. “We have discussed recalculating LBMPs for a historical time period as if there were a carbon component [c] included [in order] to get an approximation of LBMPc in real time.”
Michael DeSocio, the ISO’s senior manager for market design, said energy traders were already “using some model, some heat rate model. Now you just have to add in a carbon adder, so it’s not much different from what you do today.”
Fromer said it would take some time to digest the detailed examples, and that his company wants to see carbon pricing move ahead, but it’s “likely to have some impact on scheduling” as traders are “being forced into guesstimating on the day-ahead LBMPc.”
Scott Leuthauser, manager of regulatory affairs and business development for H.Q. Energy Services (U.S.), read a prepared statement saying his company opposes applying the carbon charge, as proposed, to external transactions because it creates additional risks for them. External resources have no control over NYISO carbon emissions and no way of physically hedging against the risk, he said.
“As we have said before, it is better for traders to assess and bear the risk,” Avallone said.
The MIWG next meets Jan. 22 to review Tariff sections impacted by a carbon adder.
New Zone J Operating Reserves
NYISO is speeding up the stakeholder process in order to implement by June a Zone J (New York City) reserve requirement and procure 500 MW of 10-minute reserves and 1,000 MW of 30-minute reserves, the MIWG learned Tuesday.
Ashley Ferrer, NYISO energy market design specialist, told the working group that creating a Zone J reserve region and associated reserve requirements can provide more efficient scheduling and procurement of resources, as well as location-specific market price signals.
The ISO is considering the appropriate operating reserve demand curve for the zone’s reserves and will present its proposed pricing as part of further discussions regarding the proposal, Ferrer said.
NYCA operating reserves with Zone J | NYISO
Establishing a separate Zone J operating reserves requirement was originally recommended in the 2017 State of the Market report and later in the 2018 Management Response to an assessment by Analysis Group of wholesale market options regarding performance assurance.
The ISO will present market design and associated Tariff revisions to stakeholders this month and next, with the Business Issues and Management committees slated to vote on the proposal in March. Assuming stakeholder approval, the ISO would submit the proposal to the Board of Directors in April and file Tariff revisions with FERC seeking approval to implement in June.
CAISO said Monday it had finalized agreements to provide reliability coordinator services, starting later this year, with 32 transmission operators and balancing authorities in the West.
The ISO expects to eventually have a total of 39 RC clients. Those that have finalized agreements include the Bonneville Power Administration, Arizona Public Service and PacifiCorp. (For a complete list, see CAISO’s website.)
“We are pleased with the progress made this past year to offer Reliability Coordinator services, and welcome our new participants,” CAISO President Steve Berberich said in a news release. “After a year of intensive planning and coordination, the ISO will now focus on developing technology and integrating systems to meet our July 1 implementation date.”
CAISO said it is moving forward to complete the NERC certification process led by the Western Electricity Coordinating Council (WECC).
CAISO won the majority of Western clients for its RC services after Peak Reliability decided last year to wind down its reliability coordinator services by the end of 2019. Peak is currently the RC for nearly all of the Western United States and parts of Canada and Mexico. (See RC Transition, California Wildfires Will Occupy 2019.)
Peak stunned the electricity sector in July when it announced it would end its RC role and withdraw from its effort to develop a regional electricity market competing with CAISO. (See Peak Reliability to Wind Down Operations.) The Vancouver, Wash.-based company said it would shut its doors as early as Dec. 31, 2019, after transitioning its customers to other RCs.
Several months before the announcement, CAISO, a Peak RC customer, said it would “reluctantly” leave Peak, develop its own RC services and offer them to others at reduced costs. CAISO’s move was seen as a reaction to Peak entering a partnership with PJM to form a Western RTO to compete with the ISO’s expansion.
CAISO, SPP and BC Hydro decided to fill the role left behind by Peak. Most of the Western Interconnection signed nonbinding letters of intent to take advantage of CAISO’s RC services. (See CAISO RC Wins Most of the West.)
In November, FERC approved a set of Tariff revisions covering CAISO’s new RC services, clearing the way for about 72% of the region’s load to sign on with the RTO, compared with 12% for SPP. BC Hydro is proceeding with plans to provide RC services for its own territory in British Columbia, representing about 7% of load in the region overseen by the Western Electricity Coordinating Council.
The transition of RC services is scheduled to be phased in this year, with CAISO assuming responsibility for California and part of northern Mexico on July 1. BC Hydro will become the RC for a large swath of western Canada on Sept. 2. CAISO will then take over RC services for many areas outside of California on Nov. 1, while SPP will take responsibility for other regions of the West on Dec. 3.
NEW ORLEANS — For a historic moment for SPP, the ascension of two women to the RTO’s Markets and Operations Policy Committee leadership was fairly low-key.
NextEra Energy Resources’ Holly Carias began her term as MOPC chair Tuesday by simply saying, “Thank you for letting me be the MOPC chair.”
Then it was down to business for NextEra’s director of regulatory affairs. She ran the meeting efficiently, wasting no time in moving from agenda item to agenda item. She conducted the votes quickly and brought the committee back on time from breaks.
“I’m glad to see you in a leadership position,” Jim Eckelberger, SPP’s chairman emeritus, told Carias during the lunch break.
Board Chair Larry Altenbaumer offered his own unsolicited comments during the opening introductions. “I think it’s a good leadership team,” he said.
Serving as MOPC’s vice chair is Denise Buffington, director of federal regulatory affairs for Kansas City Power & Light. She and Carias are only the second and third women to take a leadership position at MOPC.
Asked if two women leading a male-dominated group — as is typical in the electric industry — is a good sign for women, Buffington replied unequivocally, “Yes!”
“Obviously, I’m excited for the opportunity to take a leadership role at the board level,” she said.
Diversity and Balance
Whereas SPP made a concerted effort to increase the diversity of its Board of Directors by adding two women as members last year, SPP Vice President of Engineering Lanny Nickell said that was not the case with the MOPC appointments.
“I don’t think the Corporate Governance Committee recommended Holly and Denise to serve as MOPC chair and vice-chair, and the board approved that recommendation, to increase diversity,” said Nickell, himself a new addition to MOPC as staff secretary. “The recommendation was made because these were the two best candidates for the positions.”
Both positions opened up late last year when Chair Paul Malone cycled off and Vice Chair Jason Atwood left Northeast Texas Electric Cooperative. Having already sent out one solicitation for vice chair, SPP sent out a second for chair or vice-chair.
If anything, the board and CGC followed an unwritten rule in ensuring the MOPC chairs represented either a transmission user (Carias) or transmission owner (Buffington). As an added measure, Carias is also the first independent power producer representative to chair MOPC since Dogwood Energy’s Rob Janssen.
“Certainly, diversity of thought and skill sets and experience is important,” Nickell said. “If you look at the history of chairs and vice chairs of MOPC, you’ll note there has been an attempt to have a balance of perspectives.”
Nickell said Carias is a collaborator who tries to find creative solutions “that tend to serve the interests of a broad group of parties.”
“She seems to have SPP’s regional interests in mind when she participates in our stakeholder discussions,” he said.
And Buffington?
“She’s very passionate,” said Nickell. “She’s very good at asking the right question to get [to] the root cause of an issue. She makes us think about what we can do and what we can do better. I think they will work together to be effective leaders for the MOPC.”
Nickell has his own large shoes to fill, those of COO Carl Monroe, who served as MOPC’s staff secretary for 18 years. Claiming he won’t be as smart as Monroe, the self-deprecatory Nickell did admit, “I’ve got good people around me, so we’ll be fine.”
‘All About Process’
Carias became an MOPC member just last year, though she had previously attended the committee’s meetings in her role as director of wind development for NextEra Energy Resources. She has been with NextEra for more than 11 years, following her discharge as a captain from the Air Force.
Buffington has been a steady presence on MOPC for several years and recently chaired the Z2 Task Force. She joined KCP&L in 2010 after 13 years with the law firm Skadden Arps Slate Meagher & Flom, and she holds a law degree from American University’s College of Law and an MBA from the University of Missouri-Kansas City.
Buffington said she will focus on ensuring stakeholders receive meeting materials on time, a common complaint in annual stakeholder surveys.
“I’m a lawyer. I’m all about process,” she said. “If you’re trying to elevate the conversation at MOPC, people have to get the materials on time. I don’t like getting materials the day of the meeting and the continual updates to the meeting materials.”
That will be the least of the changes for MOPC in 2019. Under Altenbaumer’s leadership, the board has delegated additional authority to the committee, relinquishing its approval of changes to SPP’s Tariff or criteria. Unless there’s a dispute requiring an appeal to the board, MOPC will now have final authority for those changes.
“That’s a huge change,” Carias told stakeholders. “These are exciting times in SPP.”
Nickell said he and Carias plan to adhere to Robert’s Rules of Order, which was evident during Tuesday’s meeting.
“The result of [some] debate won’t go to the board anymore,” he said. “If that puts more emphasis on MOPC resolving those issues at MOPC, we’ll have to get better at following those rules. I think motions need to be clearly understood, and the best way is seeing those in writing on the screen before a vote is taken.”
The Maryland Public Service Commission extended the schedule for its review of Transource Energy’s controversial Independence Energy Connection for 30 days to allow parties to provide additional evidence on proposed alternatives.
The PSC rejected a motion by the Power Plant Research Program (PPRP) of the Maryland Department of Natural Resources to dismiss Transource’s application for a certificate of public convenience and necessity (CPCN) or suspend the schedule.
But the commission’s Jan. 15 ruling set a new deadline of Feb. 25 for the PPRP, PSC staff, the Office of People’s Counsel (OPC) and local residents opposing the line to file direct testimony (Case #9471).
PSC staff and OPC supported PPRP’s argument that the PSC should reject the project because Transource failed to examine alternative solutions as required by state law. Staff recommended the commission grant the motion, suspend the procedural schedule and direct Transource to supplement its application.
The $372 million project would add two 230-kV double-circuit lines, totaling about 42 miles across the Maryland-Pennsylvania border.
Once referred to as the AP South Congestion Improvement Project, Transource’s Independence Energy Connection project would consist of two lines. The western portion would run from the Ringgold substation in Maryland to the Rice substation in Pennsylvania. The eastern line would run from the Conastone station in Maryland to the Furnace Run station in Pennsylvania. | Transource
The PPRP said Transource had failed to meet requirements to examine alternatives if an existing transmission line “is convenient to the service area; or the use of the transmission line will best promote economic and efficient service to the public.”
The agency said the need for the eastern segment of the project could be met by the existing Furnace Run-Conastone and Furnace Run-Graceton 230-kV double-circuit transmission tower lines, each of which has only one 230-kV circuit and could carry a second. (See Cancel Transource Line, Md. Panel Says.)
Transource responded it was not required to study PPRP’s proposed alternative and said it met the requirements of state law by analyzing “over 30 study segments.”
“Disputes over whether the commission should consider an alternative are properly the subject of competing testimony at the evidentiary hearing,” Transource said.
The commission said it was modifying the procedural schedule to allow the parties to conduct additional analysis or discovery regarding the use of PPRP’s alternative.
“In response to PPRP’s motion, Transource acknowledges that as the CPCN applicant — the party with the burden of proof — it should be prepared to present evidence at the hearing to address any suggestions by other parties that the proposed project should be denied because there exists a clearly superior alternative,” the commission said. “This criteria includes the existing transmission line evaluation requirements set forth in [section 7-209 of the Public Utilities Article, Maryland Annotated Code].”
Rebuttal testimony will be due by March 18, with surrebuttal testimony and any PPRP response to public comments due April 1. The commission said it will allow live rejoinder testimony if needed during the evidentiary hearings.
Mary Urban, community affairs representative for Transource, issued a statement reiterating it has met all filing requirements under Maryland law.
“Transource has presented a substantial amount of information regarding alternatives,” Urban added. “As the case proceeds, the company will respond as is appropriate under commission rules.”
PJM said in November the project would reduce load costs by $707.3 million in net present value over 15 years, producing a benefit-cost ratio of 1.4. PJM declined to comment Tuesday.
Assistant Attorney General Sondra Simpson McLemore, who filed the motion to dismiss for PPRP, did not immediately respond to a request for comment.
VALLEY FORGE, Pa. — PJM is considering changing interconnection rules to accommodate transmission serving offshore wind generation.
Current rules allow merchant transmission developers to obtain transmission injection and withdrawal rights for DC facilities or controllable AC facilities connected to a control area outside the RTO.
PJM’s Sue Glatz presented the Planning Committee a problem statement to consider allowing merchant transmission developers to request capacity interconnection rights, or equivalents, for non-controllable AC transmission facilities.
Glatz said transmission developers have expressed interest in building AC transmission to accommodate future generation interconnection requests. The developers want to acquire capacity interconnection rights so PJM can identify the necessary network upgrades, she said.
The key difference is that the developers want to build transmission before the generation is sited. Without generation at the other end of the line, PJM cannot perform stability or short-circuit analyses, Glatz said.
PJM hopes to develop a FERC filing on Phase 1 of the initiative — focusing on rules for a single offshore generator lead line — by July.
Phase 2 will consider networked offshore transmission for connecting multiple wind sites. A FERC filing is targeted for September 2020. “We view this as much further down the road,” Glatz said.
John Brodbeck of EDP Renewables N.A. asked PJM to offer education on what open-access rights generators will have to the lines.
Theodore Paradise, ISO-NE’s former assistant general counsel for operations and planning, who has joined transmission developer Anbaric as special counsel, asked for a discussion on how HVDC facilities are modeled in PJM.
The committee will be asked to approve the problem statement at its next meeting.
PJM Seeks Fix on Queue Filing Errors
PJM is proposing a one-sentence rule change to help developers avoid being removed from interconnection queues because of minor errors or omissions.
Interconnection customers are generally granted up to 10 business days to resolve deficiencies found by the RTO. But under changes initiated in 2016, requesters must clear all deficiencies by the last day.
The changes were intended to dissuade developers from late submissions. But PJM said requests are not being submitted any earlier and the changes were undermined by FERC rulings reinstating applicants removed for minor errors.
PJM’s Susan McGill presented the PC a proposed problem statement to ensure that all applicants have up to 10 business days to correct deficiencies, whether they enter on Day 1 or the last day of the six-month queue.
“We can’t have another queue where people get bumped out … they go to FERC and get waivers [to return]. It’s very disruptive,” Vice President of Planning Steve Herling said.
Since the AA1 queue opened in May 2014, 50 to 60% of interconnection requests were submitted in the last month of the queue.
Prior to the 2016 changes, which resulted from the Earlier Queue Submission Task Force, about 18% of projects submitted in the last month of the queue were withdrawn for deficiencies. After the EQSTF changes, that withdrawal rate increased to 24%.
PJM is proposing to give all projects 10 days to address problems by removing the following sentence from the Tariff: “Any queue position for which an interconnection customer has not cleared the deficiencies before the close of the relevant new services queue shall be deemed to be terminated and withdrawn, even if the deficiency response period for such queue position does not expire until after the close of the relevant new services queue.”
“We’re not looking for reasons to get rid of you,” McGill explained.
PJM’s Dave Anders said Manual 34 allows the first discussion of a problem statement to include a proposed solution if the committee chair determines “the problem presented is sufficiently simple.”
Herling said, “We do have more changes we think need to be made [to interconnection queue rules]. But that will require a more robust conversation.”
PJM Pondering Wind Capacity Measures
Wind generators could see lower capacity credits under rule changes being considered by the RTO.
PJM’s Tom Falin presented the PC with the updated results of the RTO’s analysis of wind and solar resources’ effective load carrying capability (ELCC) — a measure of the additional load that a group of generators can supply without a reduction in reliability.
Effective load carrying capability is a measure of the additional load that a group of generators can supply without a reduction in reliability. | PJM Renewable Integration Study (2014), General Electric
The new results use the 2018 reserve requirement study (RRS) capacity model, which shows nameplate capacities for 2022/23 of 14,620 MW of wind and 5,290 MW of solar.
PJM found the average wind ELCC between delivery year 2009/10 and 2017/18 was 11.5%. That suggests the RTO’s current practice of using wind’s average capacity factor of 17.1% overstates wind’s value, Falin said. The median capacity factor over that period was 8%.
“We feel [the median is] a much, much better indicator of the reliability value” of the resources than the average, Falin said.
PJM found the average solar ELCC since 2012/13 is 42.3%, close to the average capacity factor of 42.1% and median capacity factor of 40.9%.
Falin posed two questions to stakeholders: Should PJM continue with its original proposal to change the intermittent resource capacity credit calculation from an average value to a median value? Or should it base the calculation on the ELCC methodology?
He said the advantage of changing from average to median capacity factor is “it’s much less of a black box” than ELCC.
Although the figures represent ELCC values RTO-wide, PJM said the ELCC must be allocated to individual generating units based on individual unit performance.
PJM calculates capacity credits for existing wind resources by multiplying the ELCC by the total nameplate. The RTO has three options for prorating the total capacity credit for existing units:
The average output of an individual unit during a specified number of daily peak hours in each year for which the unit was in-service;
The average output of an individual unit during the daily peak hours in which the loss-of-load expectation (LOLE) is non-zero in each year for which the unit was in-service; or
The average output of an individual unit during hours ending 3, 4, 5 and 6 p.m. during the summer season in each year for which the unit was in service.
Falin said the second option could involve as few as three hours or as many as 12 per year. The last option — PJM’s current method — has the advantage of being based on a lot of data, making it more stable than the other choices. But Falin said it also includes many hours with no LOLE risk.
For new resources, the credit can be calculated by:
multiplying the systemwide ELCC by the nameplate of the new unit (as MISO does);
multiplying an estimated zonal ELCC by the nameplate of the new unit; or
multiplying an estimated unit-type ELCC by the nameplate of the new unit.
RTO-wide ELCC values will be updated each year as part of the installed reserve margin study.
New units will continue to have the option to provide data justifying capacity credits greater than the ELCC value. As under current rules, new units’ actual performance will be rolled in over a three-year period.
PJM wants to develop manual language and request MRC endorsement by the April meeting so that unforced capacity (UCAP) values for wind and solar can be posted by May 1 for use in the 2022/23 Base Residual Auction in August.
The changes would be effective June 1, 2022; thus, they would not affect UCAP values from prior auctions.
Transmission Expansion Advisory Committee
Dominion Plans $7.5M Substation Project
Dominion Energy plans to spend $7.5 million on a new substation to accommodate a new data center campus in Fauquier County, Va., with a total load of more than 100 MW.
The company will interconnect a new Lucky Hill substation between the Remington and Gordonsville substations on line #2199, a 230-kV circuit.
The requested in-service date is Sept. 15, 2020.
Supplemental Projects More than Double Baseline Additions in 2018
Transmission owners proposed $5.7 billion in supplemental projects in 2018, more than double the $2.065 billion in baseline projects included in the 2018 Regional Transmission Expansion Plan, PJM’s Aaron Berner told Transmission Expansion Advisory Committee members Thursday.
Most of the supplemental projects were presented by American Electric Power ($2.4 billion) and Public Service Electric and Gas ($1.46 billion).
More than half of the baseline projects were attributed to aging infrastructure.
Transmission owners’ supplemental projects have outpaced baseline projects in all but one year since 2015, totaling almost $15 billion. Baseline projects totaled only $8.1 billion over the same period. | PJM
Reliability Window Likely in June
In an update on the assumptions for the 2019 RTEP, Berner said the RTO expects to open a reliability window for proposals in June.
The 2010 RTEP will include 27 locational deliverability areas and Ohio Valley Electric Corp. FERC approved OVEC’s integration into PJM last February.
Generation with executed facilities study agreements (FSAs) will be modeled offline along with associated network upgrades, which will be analyzed separately. Berner said PJM could “turn on” FSA generation and their upgrades if there are many generation retirements but said the RTO does not expect to do so.
Travis Stewart of Gabel Associates said the American Wind Energy Association would like PJM to analyze the consumer benefits of states sharing the costs of transmission to accommodate their renewable portfolio standards. Stewart said AWEA wants more information on projects that could relieve congestion and allow PJM to access higher quality wind in the Midwest. The group may request PJM consider an RPS build-out as an RTEP future, he said.
PJM to Sunset Regional Planning Process Task Force
PJM notified stakeholders Friday that it plans to sunset the Regional Planning Process Task Force on Feb. 1 unless it receives objections from stakeholders within the task force, PC or the Markets and Reliability Committee.
The MRC voted in April 2015 to place the task force on hiatus in case it needed to be reconvened to address FERC Order 1000 or other issues. (See “Regional Planning Process Senior Task Force Placed on Hiatus,” PJM Markets and Reliability Committee & Members Committee Briefs.)
VALLEY FORGE, Pa. — It was one of the shortest Market Implementation Committee meetings in memory Wednesday as stakeholders clocked out in only two and a half hours following discussions of the must-offer exception process, FERC’s energy storage order and PJM’s indemnification rules on bilateral trades of financial transmission rights. (See related story, Shell Energy Seeks to Avoid Liability in GreenHat Trades.)
PJM May Split Rule Changes on Must-offer Exceptions
PJM may seek approval of widely supported changes to the must-offer exception process while having further discussions on revisions that lack consensus, RTO officials told the MIC.
The process behind the rule changes was initiated by Exelon to investigate issues including the process for existing capacity resources with a must-offer requirement to become energy-only resources.
The changes with widest support would allow market participants to voluntarily remove a generator from its capacity resource status by making a request to PJM and the Independent Market Monitor. It would also permit participants to request exemptions from multiple auctions in a single exception request. It would allow such changes for new resources that cannot be completed by the start of the delivery year for which it cleared.
There is less consensus on a rule that would require generators to forfeit their capacity injection rights (CIRs) if they are repeatedly approved for CP must-offer exceptions and not offered in capacity auctions for three consecutive delivery years.
Monitor Joe Bowring said the proposed changes failed to strike the right balance.
Bowring said PJM should discourage generators from holding on to CIRs for a long period of time because “they can’t make up their mind” about being a capacity resource.
“If someone has a clear plan, and they’re following it, that’s fine,” Bowring said. “We think this [proposal] allows more than that.”
Carl Johnson, representing the PJM Public Power Coalition, was also critical. “I’m struggling to find anything I like about any of this,” he said. “This doesn’t hang together to me as an effective set of rules.”
Sharon Midgley of Exelon asked PJM to move forward on the parts of the package with wide support, saying the only issue in dispute was over the RTO involuntarily seizing CIRs from generators after three years of successive must-offer exception requests.
PJM stakeholders are still debating a rule change that would require capacity resources to become energy-only after three consecutive years of exemptions from must-offer rules. | PJM
But Marji Philips of Direct Energy said her company would not support a “quick fix” based on what has been proposed to date. “The process as proposed is a little bit loose yet,” she said, adding that CIRs are “a very serious barrier to new entry.”
A few stakeholders rekindled an earlier debate over whether CIRs are generators’ “property rights.”
Gary Greiner of Public Service Enterprise Group said stakeholders need PJM’s opinion on the issue. “We’ve kind of danced on the periphery, but we’ve never come at it head on,” he said.
PJM’s Pat Bruno said the RTO may split the issue so it can seek approval of its non-controversial elements. He said the RTO will conduct additional discussions with stakeholders before the next MIC.
Electric Storage Rules Require Manual Changes
PJM’s Laura Walter gave stakeholders an update on the RTO’s implementation of rules opening its markets to electric storage, saying as many as 15 manuals may require revisions.
PJM made two filings to comply with FERC Order 841 on Dec. 3, one covering markets and operations (ER19-469) for which comments are due Feb. 7, and a second governing accounting (ER19-462), for which the comment period closed on Jan. 4. The RTO plans to implement the changes by Dec. 3.
Walter said stakeholders will be asked for feedback on energy storage cost offers at the February MIC meeting. Among the items to be discussed will be whether cost offers should be based on inventory cost (historical weighted average cost of stored energy available for discharge, adjusted for round-trip efficiency); opportunity costs (expected lost net revenue from operating in a given hour); or replacement cost (estimated future weighted average cost of charging energy over the next available operating period).
First drafts of manual revisions will be presented before July, Walter said.
